Glenn Stetson: Leo, I’ll start. This is Glenn. The short answer is yes. So the Pronto to San Mateo Connector will be set up such that those two systems can flow one way or the other. And so today, it looks like it’s more Pronto to San Mateo, but once the second plant, the $200 million a day plant expansion that we’re — that is underway today on the Pronto system that will expand the capacity of the system as a whole and gas can swing back and forth between those two systems and provide more flexibility and more flow assurance for times where there’s either preventative maintenance going on or whatever the situation might be. And that second plant is scheduled for the second half of — or excuse me, the first half of 2025. And our BD teams are — we’re going to fill a lot of that plant expansion up with Matador’s equity volumes, but certainly, there’ll be extra capacity there.
And our teams are actively working on what opportunities there are for third-party for third-party volumes that will deliver to that system, and we feel like there is a lot of opportunity given the nature of what exists today in that northern part of the basin.
Leo Mariani: And just any color on kind of where you stand with partner discussions, potential partners for that new $200 million in plant?
Joe Foran: Yes. Leo, I’ll take that question is that look, we are in a position. We have plenty of money on our RBL to fund it. We paid down our RBL over $200 million for what we borrowed on the Advantage acquisition. So that’s the use of that is that it’s there. We have over $1 billion on our RBL. We have good standing. So it’s not a problem. Our criteria is not because we need some partner we’re interested in somebody that helps bring something extra to the table that in some way that enhances the value or the efficiency of the system and the plant, so — or gives drilling incentives like what we have with San Mateo. So is out there. If we can find a partner who can enhance it, we’re interested in talking, but we’re not just trying to get financing. And that doesn’t have a lot of appeal because we already have that in place with our RBL.
Operator: And our next question will be coming from Zach Parham of JPM. Your line is open.
Zach Parham: I guess first just on your cash taxes, the guidance at 5% to 10% of pretax income was a bit better than we were modeling as we had assumed you’d be subject to the AMT. Can you give us some color on how you’re able to still defer a majority of your taxes in 2024? And any thoughts on how cash taxes will trend in 2025 in future years.
Rob Macalik: Sure. This is Rob Macalik. I’m the Chief Accounting Officer. We continue to work really hard, both internally and with our external tax providers and we try and take every deduction in tax credit that we’re allowed to take under law. In 2023, as you noted, we were down about 1% on our current tax rate. We knew that, that was going to go up for 2024. I think it is a little bit better than even what we were anticipating just as we continue to work through the kind of vague guidance that’s out there, but we feel very confident in our current estimation that we won’t be subject to the KMP, that alternative minimum tax that you referenced for 2024. We continue to evaluate that and look through just there are so many factors that can go into whether we’ll be subject to that in 2025, and we’ll continue to monitor that.
But at the moment, like you said, we feel very good about the 5% to 10% of our pretax income would be cash taxes. But like I said, we’ll continue to work and drive that down as much as we can.
Zach Parham: And then one just quick follow-up. On the cash flow statement, there’s a $68 million payment to advance this quarter. Can you detail what exactly that was and if there are any future expected payments in regards to that deal?
Van Singleton: Sure, Zach. This is Van. That was actually a tack-on deal for some additional interest in the basin that was very complementary to what we had closed on last year. And so Brian, I don’t know if you want to expand on that, but it was just more additional acreage from the same deal, which I think goes towards what we said earlier that these relationships are important. They had this interest that they wanted to move out and called us, and we were able to make a deal.
Brian Willey: Yes, Van, this is Brian. I think that’s exactly right. And so on the cash flow statement, it’s focused advanced because it’s really — for accounting rules, they treated as almost a continuation of the business combination we did before. But it’s a great deal, continue to add interest in some of the similar acres that we bought. And we’re really excited about — we already talked about the wells coming online this year as we expect to come on additional wells on the 21 Margarita wells that came on last year. So great acreage, and we really enjoy working with the merited folks and being able to continue to complete these transactions.
Zach Parham: Maybe if I could squeeze one more in. Can you detail any production that came with those acquisitions?
Brian Willey: Yes. This is Brian. So I think really one thousand BoE per day that we mentioned in the release, that really is due to that advanced acquisition, the additional advanced acreage and the interest that we got. And so I think that’s a good feel for us. And I think if we look at going forward, it’s 80% oil, 77% oil is what we got. And so it’s really, really good acreage. And so good interest. So that’s really for that specific deal. I think we mentioned earlier, we do blocking and tackling deals all the time. And our land group does a very good job at that, and they continue to add interest and add production that way. And so as we grow throughout this year, part of that growth, of course, is always that we we’ll do deals. We think that the land group has done a great job the last few years doing 200 deals a year and expect they’ll continue to do that this year.
Joe Foran: We appreciated also that in [Indiscernible] worked with us on that transaction. They were primarily some minerals and some overrides and it was a good fit for us. And so we appreciate the follow-up and that we got that. It isn’t huge. But if we do nothing like this, they’ll have a favorable impact.
Operator: Our next question will be coming from Oliver Huang of TPH & Company. Your line is open, Oliver.
Oliver Huang: Just on the operational side, I think you all highlighted about 60% of completions this year are going to be using Simul- or Trimul-Frac ops. Just how much of the expected cost benefit and also the efficiency benefit from a cycle time perspective have kind of been underwritten into your 2024 outlook as it sits today?
Christopher Calvert: Yes, Oliver, this is Chris Calvert. That’s a great question. You’re referring to Slide 15 in the deck where we’re talking about our completed lateral footage efficiencies. And really, that has kind of been the main focus of our operational teams is how do we put forward those capital efficiencies that really help insulate from any sort of OFS inflation or deflation. And so when we look at the cost savings associated with Simul-Frac and/or Trimul-Frac, a lot of those savings are baked into our capital budgets. We pilot-tested Simul-Frac in 2021. So I think now that it has become such a large percentage of our portfolio, we do calculate that and factor that into our budget, forward-looking budget. Trimul-Frac from an efficiency standpoint, we still — like I said, we’re in process of doing that right now.
And so as far as the efficiencies of what we will gain. I think we’ll be talking about that more on the call in April. But we’re excited about Trimul-Frac. We saw about a 20% to 30% improvement in capital efficiencies from the completion standpoint when we move to Simul-Frac. And so we’re expecting some similar numbers, a significant improvement from an operational efficiency standpoint by incorporating Trimul-Frac into the operational portfolio.
Joe Foran: Chris, why you’re on that area, I was going to ask Tom to talk about the U-Turn wells and the capital savings there. The same thing, and you look at Slide M on Page 16.
Tom Elsener: Sure. Thanks, Joe. Albert, this is Tom Elsener. Yes, looking at Slide on the U-Turn wells. As we’ve kind of talked about before, we drilled our first 2 U-turn or first 2 wells as we’ve called them before done on our Wolf property in Texas. And we’ve had very successful production results from those wells that even though they’re U-Turn wells, they performed just like a straight 2-mile-long lateral, very high pressures and IP rates of between 2,100 and 2,400 BoE per day. You wouldn’t know the difference if it was a U-Turn or 2-mile lateral from the production results. We monitor those wells for several months now. And combined with the great cost savings that the team seemed to execute down there, we’re ready to kind of do a few more of those.
And I think we’ve highlighted that there may be up to 20 or so U-Turn wells that we may mix into the drill schedule kind of over the next kind of 2 years. We had some really nice rock that we would like to put into the program, just want to drill more of U-Turn. And so I think we’re very excited for those. And that I think they’ll be very successful. We still are kind of in the learning phase. We’re going to learn about some different targets in different areas. So we still — I still think we’re kind of in the walking mode. We’re not quite in the running mode yet. But I think we’re very optimistic about it.
Joe Foran: Billy, your group and you’ve had a lot of innovations for managed pressure drilling to the rig design. Do you want to say anything else you’re working on?
Billy Goodwin: Yes, sir. I mean that was a good project, and we have Patterson rigs out there on it and had some good engineers and did a really good job there, getting those wells drilled and completed, and it was a great operation, just while we’re at it, go ahead and give a little shout out Patterson and everything they’ve done through the last couple of decades. They didn’t just build a rig and leave it there. They’ve continued to add with their technology and their operating systems and techniques and this is another one they were out there with us, had extra people out there to make sure it’s a good successful operation. And also there frac side next year and all we’ve worked with them. They do a great job for us. I like to mention Halliburton, Schlumberger and others that work with us and help us stay on top of our game.
But really have done a lot of good with Patterson from the U-Turn wells, especially was a highlight. But also now we picked up the larger rig, 2,000-horsepower rig, and we’re looking to do great things with that as well. We’re just getting started with it and got our — got the rig out there put together, got our surface hole and the media and fixing to get to the game time, show time with getting after the production hole, and we’re expecting to set some new records there. And while we’re talking about record at Maxcom group, where our geologists and engineers work together. They’ve been doing a great job there and coming up on our Board week, a week or so ago, we had 262 records there since we started Maxcom and we already upped that 3 more to 265.
So they just continuously get better and better, and that’s worked out to be just a great operation for us there. And all of our hands coming in. We try to work all of our new people, engineers and geologists spend a little time in there and get to know each other and it makes us a lot better on both sides of the operations. And we talk about the records and the money we’re saving, drilling faster, but — and staying in zone, and that staying in zone is a big part. We don’t talk about a lot. We talk about all the money, $40 million we saved with all the records in the time. But also, when you drill a 10,000-foot lateral and you stay in zone, 99% to 100% of the time, and you get an extra 10 barrels of oil per foot, you get an extra 10,000 barrels of oil.
I mean that’s a lot of money right there. So all around just a great, efficient program and drilling and completion both have been doing a great job. Chris, do you want to add something.
Christopher Calvert: Yes. Oliver, I’ll just kind of close the loop. I think what it really comes down to operationally for us is we looked for technological improvements so we can continue to push every single year. And those come through relationships such as Patterson Nextier and other vendors to help us drill and complete wells faster but then also just engineering and people efficiencies that we find here in the office. And that’s — you look at something like Trimul-Frac or Simul-Frac, and that’s really just kind of reimagining a process. It’s been around for a long time, and that comes from the people side. There’s not a lot of new technology that goes into a Simul-Frac or a Trimul-Frac. It’s just reimagining a process of how to make it better and more of a win-win situation for us and our partners, which in this case would be Patterson Nextier, Halliburton.
So I think it’s a really good combination approach of how we look to maintain and maximize our capital efficiencies from the operations standpoint.
Joe Foran: Speaking of the efficiencies, we — while we’re giving shout-outs need to do some for Forrester Smith, who is out there all the time, pipe is there. We don’t have to wait on it. I appreciate him and
Christopher Calvert: Yes, correct, Joe. There’s a lot of people. The list is numerous. But I think when we talk about anything that we’re looking at as far as just timing and TILs and things like that, if you don’t have pipe ready on location when you’re ready to case a well, you’re going to be held up and our service provider has been really our casing provider for decades. And so I think you have relationships that go back that help weather the bad times and flourish in the good times. And so I think whether it’s Halliburton, Patterson Nextier, the casing companies, it is something that we value at a tremendous level, and we continue to kind of push forward to make a win-win situations for both the vendor partnerships and Matador itself.
