I mean they turnkeyed a lot of their frac operations and we’re going to self source and do a lot of stuff there. So there’s a lot of low-hanging fruit on the operations side. So those are some of the big ticket items. And we’ve already seen a lot of that, which is why you’ve seen us increase a lot on the operational side.
Steve Riney: Yes. And Neil, I’d just add, if you went back to the Permian slide deck that we published in February, we specifically pointed out three areas where we felt like Callon was significantly kind of off the mark in terms of where we would want to be on LOE per BOE, workover cost per BOE and downtime percent. And they’ve – Callon has a history of a much higher well failure rate and including for new wells. They have a higher rate of ESP failures than we do. And many of those are around – we feel around their equipping choices, and we’re already making some changes on a proactive basis in that – even on some of the wells that they’ve already drilled and completed and equipped. There was a lot of inefficiency around compression and the use of their compression fleet, and we’re making across a larger set of operations, we can make more economies of scale around compression optimization and even on the rate negotiations for compression costs.
As John pointed out, they have a tendency to use a lot of ESPs for which they purchase power. That’s very expensive and a big contributor to their LOE per BOE. They use a lot of contract labor, a lot of our supply chain aspects of using APA rates around services and around product using volume discounts that we get across the larger operations and just reducing overall usage. They had a very high water handling and disposal costs, which we believe we can do much better at. They had a high rate of rental, rentals of ESPs, rental of compressions where we think we can do better at that as well. On the capital side, we’ll use more technology to drill to use – to decrease average drilling days on wells. We’ll get better rig rates. We’ll do a better job of rig moves because we’re not moving rigs across the basin between the Delaware and the Midland Basin.
We will use spudder rigs generally for a lot of the wells that we drill. They did not have a practice of doing that normally. Frac rates will get better at proppant costs; again more supply chain type of stuff. And then on facilities, we – they typically have built facilities spec. We typically try to modularize that. We will typically go to multiphase flowing through a single line. They like to use test separators and meter three products in three different lines. So we think there’s just – and there’s just a whole bunch more of stuff that we’re going to be looking at and doing to reduce LOE per BOE and downtime and the work over costs.
Neil Mehta: That’s a very thorough and helpful explanation. Thank you team and good look as you bring the asset into the fold.
Steve Riney: Thanks Neil.
Operator: Thank you for your question. We will be taking one more question. Please stand-by. We now have a question from Paul Cheng of Scotiabank.
Paul Cheng: Hey guys. Good morning.
John Christmann: Good morning, Paul.
Paul Cheng: Good morning, John. Steve, I have to apologize. When you talk about dry hole, I sort of missed that. Can you repeat it? I think you’re saying that you have a way of in share name on B52 that’s I think $40-some-odd million. So what’s the remaining with the driver expense at 123 [ph]. The second question is that yes, go ahead, please.
John Christmann: Well, I’ll jump in. The – there’s one dry hole in Suriname, which was related to Bonboni up in the north. It was one that we held and weighted because we didn’t know how the North would factor in on the future exploration side. And so that’s why we took that one now. And then we went ahead in Alaska and rolled off the two wells that we failed to reach TD on simply because the decision was made that it would be easier to go back and redrill those prospects with brand-new wells. And so that’s what the dry hole expenses were for.
Paul Cheng: I see. And John, on Alaska in King Street discovery, can you share that what’s the thickness of the case one that you have interpolated that do you have any data about the permeability or that any information that you can share?
John Christmann: Well, it’s very preliminary, Paul. But we’re excited about both. I mean these are not shallow wells in the Brookian play to high-quality oils – we were also very pleased with the early data, but we need to get the rock data back into the lab and analyze that and go through all that before we really share anything. I think one of the big read-throughs on King Street though, it was the smallest and the most risky of the three prospects, even though it’s the one we got down all the way, but there is a very positive read through in the Upper Zone at King Street for the big target in Voodoo, so it’s very exciting. And if anything, it has us feeling even better about the program and the acreage going forward. I mean we’ve moved 70 miles to 90 miles east of working hydrocarbon system.
Truly wildcat area, and now we’ve proven petroleum system. We’ve proven oil, and there’s also very high-quality sand there. So a lot to get pretty excited about going forward in Alaska.
Paul Cheng: Right. And John, you’re saying that you’re going to redrill the two new well for Sockeye and Voodoo is that going to be done? Or that is going to be drilled in the next drilling season? Or that you guys have not decided may get pushed out further?
John Christmann: I’ll just say, it’s highly likely that we redrill both prospects – but it’s – we’ve got to work through the partners, and we don’t have to make decisions yet on the 2025 drilling program. So we’re – it’s something we’ll be working through with the partners over the next several weeks. But at this point, it’s something that could be done in 2025. It doesn’t have to be done in 2025, but we’ll be working through the partners with that.
Paul Cheng: Okay. Thank you.
John Christmann: You bet. ]
Operator: Thank you. This does conclude our question-and-answer session. I would now like to turn the call back over to John Christmann for closing remarks.
John Christmann: Yes. Thank you. In closing, our Permian is performing extremely well, and we have just bolstered it with the addition of Callon and is now approximately 75% of the company. We will be integrating Callon over the next couple of quarters. And by the fourth quarter, you should start to get a good picture of what we can do with the Callon assets. We have pulled from some frac capital into the second half of the year which should really give us strong momentum as we head into 2025. On the cost synergy side, we have increased our expectation by 50%, and we’ll capture most of these by year-end and we believe there is even more to do beyond that. And lastly, we’d like to make more progress on debt reduction by the end of the year while also meeting our 60% shareholder return commitment. Thank you very much for joining us today.
Operator: Thank you. This does conclude today’s conference. You may now disconnect.
