It’s essentially, the same rock and the same tools, but the culture that we built here at this Company with that laser focus on the conversion process of rock into cash flow, is felt by every employee in the Company. And when you have everyone leaning in the same direction on cost and efficiency, as long as we can continue to give them good rock, they’re going to generate the outstanding results that we’re known for. So, I know that’s a little bit of motherhood and apple pie, but it’s — I’m really proud of the organization for — through all the cycles we’ve been through over the last 10 years, what hasn’t changed is an unrelenting focus on delivering, best-in-class execution, highest margin barrels at the lowest cost.
Roger Read: I appreciate that. I’m not going to be in between motherhood and apple pie here in the U.S. So, I’ll turn it back. Thanks.
Travis D. Stice: Thanks, Roger.
Operator: Thank you. One moment for our next question. Alright. Our next question comes from the line of Derrick Whitfield of Stifel. Please go ahead.
Derrick Whitfield: Good morning, all and thanks for all the incremental disclosures this quarter.
Travis D. Stice: Thanks, Derrick.
Kaes Van’t Hof: Thanks, Derrick.
Derrick Whitfield: Building on an earlier question, how should we think about 2024 maintenance capital, run rate, assuming the benefit of deflation and your current operational efficiencies?
Kaes Van’t Hof: That’s a good question, Derrick. And I’d probably say that maintenance CapEx would be $100 million to $200 million cheaper, 30 wells maybe, Danny.
Daniel N. Wesson: Yes. I think, we’re kind of looking at it, like, our maintenance our case for 2024 is kind of a maintenance activity case. So, flat activity outfits a little bit of a growth, but, if we were to try and maintain a flat production profile, you’d probably be in the line of 20 to 30 less wells in the year.
Travis D. Stice: You know, Derrick, while you’re on that topic of maintenance CapEx, I might just point you to slide seven, we’ve had that slide in there a couple of times, but it shows maintenance CapEx, which Danny just defined, is kind of holding, the fourth quarter production flat for next year. And I just want to show you what our breakeven prices are on that slide, $32 a barrel to cover maintenance cap, maintenance CapEx, $40 barrel to cover our base dividend. So, that kind of goes back to my cost and execution comments that ultimately translate into a very protected business model even at low commodity prices.
Derrick Whitfield: That’s great. And as my follow-up, with respect to your non-core asset sales, how should we think about the market value of what’s being retained by Diamondback and how that will be realized over time now that you’ve exceeded your disposal target?
Daniel N. Wesson: Yes. Good question, Derrick. We do lay out some of our remaining JVs that we have on slide 26. Yes, I think some of those logically are monetized at some point in the coming years. I don’t think we’re in a huge rush to do so, but, in most cases, we’re kind of a non-op partner to these JVs that do have a ton of value just not something that we can commit to monetizing today.
Derrick Whitfield: All done, guys. Thanks for your time.
Kaes Van’t Hof: Thanks, Derrick.
Travis D. Stice: Thanks, Derrick.
Operator: Alright. Thank you. One moment for our next question. Next question comes from the line of Kevin MacCurdy of Pickering Energy Partners. Your line is now open.
Kevin MacCurdy: Hey, good morning. I appreciate the commentary on industry consolidation. Digging into your cost structure comments a little bit, now that you’ve had FireBird and Lario in house for almost a year, can you comment on the level of cost synergies you’ve created in those transactions or maybe just share with us your analysis of Diamondback costs versus peers. I’m just trying to get a sense of what kind of uplift assets get when they’re incorporating it to Diamondback in your cost structure?
Kaes Van’t Hof: Yes. I mean, that’s a good question, Kevin. I hate to say it, but we didn’t win those deals because we were buddies and been left and other people. So, I think we bid the most, but we bid the most because we could underwrite it with the lowest cost, right. At the time, I think some Lario well costs were near $8.5 million, $9.5 million for 10,000 foot lateral, and we were drilling them at [$6.5 million to $7 million] (ph). And so that’s kind of been our mantra for a long time. I would just say generally if you split the two deals out, Lario was an execution deal because we knew we could drill those units cheaper, and execute on large scale development. I would say, FireBird is more of a technical deal. And, we had a technical view of that particular area that the basin could move further west, particularly in the northern top portion there’d be some multi-zone development that looks really good.
I think we’re conservative on the multi-zone potential of the central block. And now feel a little more confident about the Wolfcamp A and Lower Spraberry and maybe being wind wrapped in that area. And also, with the benefit of that block being so contiguous, we’re able to bring a 15,000 foot lateral manufacturing process to that area. So, now we underwrite these deals at our cost structure, which if you look at our cost structure versus others that means we should get more of those properties at the same rate of return because of our ability to execute.
Kevin MacCurdy: Great. That’s only one for me. Appreciate taking my question.
Travis D. Stice: Good question, Kevin.
Operator: Alright. Thank you. One moment for our next question. Next question comes from the line of Jeoffrey Lambujon of TPH & Co. Your line is now open.
Jeoffrey Lambujon: Good morning, everyone, and thanks for taking my questions.
Travis D. Stice: Morning, Jeff.
