Eric Hambly: Yes, okay. Thanks, Leo. There are 2 primary factors that are driving lower production with sort of similar well counts relative to 2022. First of all, our new 2023 wells come online a bit later in the year on average than our ’22 program, so when you do the average for the year. It’s a little bit lower. Second and probably most significantly, our operated 2023 program is almost evenly split between Karnes, Catarina and Tilden locations. And as we’ve highlighted on our recent calls, we delivered significantly improved Karnes and Catarina results in ’21 and ’22 by applying our enhanced completion design. We have not drilled and operated Tilden well since 2019. So we’re hopeful that our 2023 Tilden wells will see the same level of performance improvement as our recent Karnes and Catarina wells.
However, our guidance for ’23 for Tilden is based on type curves that are aligned with pre-2020 wells. So a combination of the mix and our expectations for an area we haven’t been to sort of driving our average production per well down a bit from what we actually experienced in 2022. And as Roger noted, we’ve been targeting production from the Eagle Ford in the 30,000 to 35,000 barrel a day range. We have, in the last 2 years, exceeded our expectations from the capital we’re deploying there, getting higher realized production than we expected. We would love for that to happen in ’23, but we are not assuming that it will.
Leo Mariani: Okay. That’s very helpful. On the color there — on the Eagle Ford, I just wanted to follow up and ask a little bit about CapEx here. As I look at the plan for 2023, very, very front-end loaded, 70% in the first half, 30% in the second half. I know you guys also were front-end loaded as well in 2022. However, as kind of the year progressed, you guys did kind of make the decision to raise CapEx? I know there were some extra projects to get in there. I’m just trying to get a sense here. You’ve got a pretty wide range of CapEx in terms of what you have there in 2023. I guess I’m just trying to understand if there’s a caught a little bit between kind of the bottom end and the high end of the range? And is there potential for other activity to come on late in the year, if you guys decide to do more in the Gulf, if partners are proposing wells? Maybe just kind of talk through that dynamic a little bit.
Roger Jenkins: Thanks for that question. I appreciate that, Leo, this morning. The way we think about it is we — it’s quite common to have a wider range for many of our other peers — so I would be dumb not to have one for myself. We don’t — I don’t see as many — like last year, we’re drilling Samurai. We had incredible success there. And we were seeing additional zones to complete. We found some additional pay. This year’s program, we’re completing a non-well that we — others very successful well at Dalmatian. So we know what that is. We’re drilling a well at Mamelodi development well up in the middle of several other wells to accelerate that production. So I anticipate like another monad coming out of it. The risk we have on CapEx is phasing by super majors in and out of Oxy and Chevron involving Lucius in St. Malo.
