Herbert Vogel: Sure Tim. But one thing I want to correct you on that there, there would be four producers, just one when we took a pilot hole down first, then we plugged back and drilled the lateral. So, there are four wells there. Just one of them we have that vertical that we just got the data on. So, it’s great to hear that there’s prospectivity in the Wolfcamp A. I would say we are not counting that. If we’re surprised and that the maturity is higher for some reason there than we expected to be, that would be great news. But we’re really counting on this being more a migrated oil play, which I’ve talked about before, which is oil comes for a bit deeper in the basin and migrates into the sandstone intervals. And that’s why they are so prolific up there.
Tim Rezvan: Okay. And then are these initial four wells Dean? All Dean or–
Herbert Vogel: Yes, they are. They’re all Dean wells.
Tim Rezvan: Okay, that’s great. Appreciate that. And then as a follow-up, I think the comments on the Briscoe pad and the stacked pay opportunities are pretty interesting. Some other public companies are talking about that. I know it’s early days from one pad, but big marketplace debate was on the validity of your claims that you had 300 locations there. And I guess just to help kind of frame a resource, if the stack pay proves to be something you can replicate, does that 300 location count kind of move up dramatically? I’m just trying to understand sort of what the significance is of this test that you’re doing that you disclosed? Thank you.
Herbert Vogel: Yes, Tim, I would say it’s not that much of a big increment in the test. The only difference is that the lower wells are fully bounded versus other places, they’ve been half bounded. But we’ve had fully bounded in the upper interval and several other pads. The thing to note is these are space is about 625 feet and we’ve done that before. These go between 2 different — subtle differences in the landing zone in the upper Austin Chalk or the middle Austin Chalk and the upper interval that we’ve developed. So, it’s just really exciting because of how productive they are, how oily they are and how NGL-rich they are. And those wells on that one pad are between 11,600 and 14,500 feet long. So, we didn’t have difficulty executing there.
And the other three are between 11,900 and 14,000 feet. But there are long laterals, too, and that just really helps the economics also and their oil rig. So, really excited about it on that area, and you can see the strength of the wells and just how they started. But it’s not like they’re a really big step in any way other than the bounding of the lower Austin Chalk wells.
Tim Rezvan: Appreciate the color. Thank you.
Herbert Vogel: You bet.
Operator: [Operator Instructions] Our next question comes from Oliver Huang with Tudor, Pickering, Holt & Co. Please proceed with your question.
Oliver Huang: Good morning all and thanks for taking my questions. Just wanted to start on the efficiencies. Certainly good to see the continued capture there. I was just kind of wondering of what you all have kind of achieved in Q1? Is it something that’s already been baked in for new plant activity starting in Q2 when you’re kind of providing the quarter ahead of full year outlook? Or is there kind of a wait-and-see aspect to it since it’s only a quarter before kind of taking that fully on that incrementally faster case that we saw?
Herbert Vogel: Yes, Oliver, when we change guidance, that means we’ve got a lot of confidence that it’s appropriate to include it. So, we’re continually working new aspects of efficiencies in and we have quite a laundry list that our team is running through right now. That looks attractive, but we’re not counting once unless we see them working. So, the big ticket items for us right now are the increased substitution of natural gas for diesel and frac pumping operations on those DGB fleets that we’re employing. And Wade mentioned those on the prepared remarks. And that has the added benefit of the reduced CO2 emissions from completion operations. Then we’re seeing quite a bit in the way of efficiency gains in drilling. So this translates to number of feet we drill per day.
They’re really — it’s more advanced and reliable downhole equipment, so you don’t have to trip the bit as much. And we’re using rotary steerable assembly, so we can keep the bid on bottom longer. That helps also. Then on the efficiency — cost efficiency side, a big one is using existing central production facilities that now are sitting there with some latent capacity and that avoids the need for capital into new facilities. We knew all along about what’s going to happen, and we’re just starting to see it really happen in a pretty significant way now. And then we’re also bundling some services between South Texas and Permian. So we’ve got the benefits of the scale of the full operation between the two areas and that helps. And then you know how activity has reduced, so rig counts are down, frac spread counts are down.
So, we’re actively rebidding services and seeing discounts that way. And I can’t tell you when that will stop or how much more we’ll get there. But that obviously is a contributor. So, that’s a list of things that I’d say we’re highly confident and not a list of things that we’re still pursuing.
