Kaes Van’t Hof: Yes. That’s an interesting observation Charles, and it’s certainly not lost on us. You’ve had a couple very large buyers do a couple of deals in the basin and out of the basin. They could kind of do whatever they want, it seems like, but, I would just say generally industry consolidation has happened is continuing to happen. I think a lot of the privates are gone, as you mentioned, to logical acquirers. I would just say that there may be less buyers of assets, but they’re all very well-funded good operators, big balance sheets, and competitive. So, I think we just have to stick to our zones and our underwriting philosophy, which is our cost structure, our rates return internally, lot of hurdles for commodity price and usually that has resulted in more assets coming to Diamondback because you can underwrite wells drills at $1 million or $2 million cheaper. We can run LOE above cheaper, that’s the kind of stuff that accretes to our shareholders.
Charles Meade: Got it. Thanks for that. That’s it for me.
Kaes Van’t Hof: Thanks, Charles.
Travis D. Stice: Thanks Charles.
Operator: Thank you. One moment for our next question. Our next question comes from the line of Arun Jayaram of JPMorgan Securities. Your line is now open.
Arun Jayaram: Yes. Good morning, gentlemen. I wanted to keep on the A&D theme. When we are assessing the potential of a large private or one of these unicorns to potentially consolidate, does it just come back to price, or is there something do you think that they think about in terms of the independent versus major oil business model that could be advantageous to a company with, like, Diamondback who’s in Midland and again the lowest cost structures in the industry?
Travis D. Stice: Yeah. Arun, we don’t spend a lot of time thinking about what sellers think. We just think about what is the best opportunity available for our shareholders and creating shareholder value for our shareholders. And you know at the end of the day, I think Diamondback hand on heart as one of the best positions remaining in North America and the best cost structure. And that should be a, a very winning combination for our shareholders for a long time here.
Arun Jayaram: Understood. I want to maybe switch gears and just talk about the DUC efficiency gains, really surprised to see this year the drilling efficiency gains seems like the drilling efficiency gains are outpacing maybe what we’re seeing on the completion side. Are you guys recalibrating the call it the rig to frac crew ratio, but give us a sense of, maybe what you’re doing on the drilling side for these efficiency gains and maybe help us recalibrate what that drilling the SimulFRAC crew ratio looks like today?
Travis D. Stice: Yeah. It’s interesting. We really haven’t thought about the rig to crew ratio in a long time because just changed so much. I think we’ve moved to a world where we know how many wells we need to drill and how many wells we need to complete in a year to hit numbers. And the drilling side, maybe a year ago that was 15 to 16 rigs for a full year. And now this year, in upcoming, it looks more like 14 to 15. So, the amount of work that our planning team does on the plan and how we’re doing relative to plan is pretty astounding and how far ahead they are on these paths. And when we need to pick up a rig and when we need to drop it, you’re really kind of just targeting, can we keep those silent track crews busy consistently? And I would guess, I guess the number is kind of in that high threes, almost four rigs to one SimulFRAC through today.
Kaes Van’t Hof: Yeah. Arun its Kaes. Our goal is to keep the drilling program ahead of the SimulFRAC fleet and just keep the SimulFRAC fleet moving in efficient just like we want to keep rigs moving from pad to pad without waiting on pack instruction or whatever. So we kind of see them as two different programs altogether, knowing that they’re very dependent on each other. But I think the, the drilling and completion teams both this year have really done an excellent job of leaning in and pushing the machine to the limits and finding the little pieces of efficiency gains that can pick up. And we continue as we’ve always done to tinker and find better ways to execute our development strategy and build a better mousetrap. And when we find different ways to design these wells and execute that. We’ll lean into it and continue to chase that the efficiency line.
Arun Jayaram: Great. Thanks a lot.
Operator: Next question comes from the line of Scott Gruber of Citigroup. Your line is now open.
Scott Gruber: Yes. Good morning and congrats on another good quarter. I want to follow-up on Arun’s question, just on the activity set in the next year. And get some more clarity on the plan for the DUCs. And so it sounds like you could be running, the 14 or 15 rigs. Will you end up drilling, 330 or so wells by running 14 or 15 rigs, or will the base plan for next year contemplate a drawdown of some of those excess DUCs?
Kaes Van’t Hof: I don’t think we’re planning on drawing any down, absent any in the field issues. I think generally, we feel a lot better at this level of DUCs for the size of projects that we have ahead of us. Earlier this year, we were getting pretty close, that the rigs or the frackers were getting pretty close to the rigs getting off location and 20 well pad or 24 well pad or however you want to break it up, you have to have all 24 wells done before you can bring on the drilling side, before you can bring the fracture in. At least that’s how we do it. And that’s why that kind of 150 number, we mentioned feels like a much more balanced number going forward.
