Mike Henderson: Hi, Scott, it’s Mike here. I’ll hopefully answer that question for you. In terms of the runway that we’re looking at, at the current consumption rate, current activity rates, I think we’ve disclosed publicly that you’re looking at almost two decades or up to two decades of — maybe even more than two decades of potential inventory there. So that maybe gives you a fuel for what we could be looking like in the future. And you’re absolutely right, based on the performance that the team has delivered there, not only from a well productivity perspective, but from an execution perspective as well, I mean, some of the drilling completion results that the team’s delivered since they’ve got back to work in the middle of last year, absolutely competing for capital.
And I would remind you that while maybe the completion activity, wells to sales is from and Permian. We do have a pretty heavy drilling program this year, which will then set us up well for 2024. So we’ve kind of preempted this a little bit in terms of the performance with the additional drilling. We’ve been looking for those wells. We’re not probably going to see those wells coming to sales until the early part of next year. But you’re absolutely right, based on the performance that we’ve seen since getting back to work there, that asset is definitely going to be competing for capital as we go forward.
Lee Tillman: Yes. And if I — maybe if I could just jump in for a minute as well, one thing I want to highlight is that, in the Permian numbers now, we have fully integrated what we refer to as the Texas Delaware oil play, the Woodford-Meramec oil play and it’s been very successful for us. It has now migrated for more of an exploration play into really part of our base capital allocation within the Permian Basin. And so that’s another tranche of inventory that has now moved in to that asset team. And that’s unique in the sense that, I’ll just remind everyone that our Permian and Oklahoma teams, they are integrated teams. And so it makes absolute natural sense for that Woodford-Meramec play to migrate into a team that already has such broad experience in how to develop those two zones.
To your other question around acreage addition, what I would say to that is that our M&A framework remains unchanged. And if anything, the addition of Ensign probably rates that are even further. We still look at everything within our core basins. But I would just tell you that today, we don’t see anything in the market that really satisfies what is a very demanding M&A criteria.
Scott Hanold: Got it. And just to clarify one thing on — you said there’s two decades of inventory there. Are those extended lateral? Are those two decades of extended laterals?
Mike Henderson: Pretty much, Scott. There’s maybe — it maybe tails off to the back end, but predominantly extended laterals. And quite frankly, the team have been very active converting some of those smaller SLs to XLs. So maybe some of those SLs that are at the back end of the portfolio at the moment. Expectation is that we’d be looking to convert those to longer laterals over time.
Scott Hanold: Okay. Understood. And then, my follow-up question is going back to E.G. again. Thinking about the contract kind of rolling over at the end of this year, how are you positioning for that? Like, what steps are you taking right now to look at what is the best way to kind of optimize it going forward? Do you expect to sign some sort of a hard longer-term contract? Or do you want to keep it more open and flexible just to be more opportunistic with it? But just give us a sense of how you’re looking at setting up the pricing dynamics starting in 2024.
Pat Wagner: Hi, Scott, this is Pat. I’ll take that one. Yes, obviously, we’re getting ready to market on January 1, 2024. We will be going to market shortly with an RFP for global LNG providers. And that will be, as Lee has said, linked to global LNG prices, what marker is still to be determined, but we’ll have a big process through that and expect to tie up those contracts probably in Q3.
Scott Hanold: Understood. Thanks.
Lee Tillman: And I — Scott, there’s still details to be worked out there, but we believe that there will be competitive tension in the market for such an advantaged set of LNG cargoes that are proximal to the European market.
Scott Hanold: Right, right. What is that cost benefit do you think relative to, say, like U.S. — shipping U.S. volumes?
Lee Tillman: Well, I think we look at it through the lens of kind of how does that look relative to where we stand today. And when you think about the movement — the bulk movement from a Henry Hub link to a global LNG link, I mean, the torque there, regardless of where absolute gas pricing goes is going to be pretty significant. I mean you’re going to be talking about 2x or 3x kind of uplift as you move to a more index — global index contract..
Scott Hanold: Understood. Thanks.
Lee Tillman: Thanks, Scott.
Operator: Our next question comes from Doug Leggate from Bank of America. Please go ahead with your question.
Unidentified Analyst: Hi, good morning, guys. This is actually on for Doug. I’ve got a couple of follow-ups on E.G. First one, can you discuss what your decline rate is and what the infill drilling opportunity could do to stem that decline? And secondly, you guys highlighted that there will be a turnaround or a turnaround has been completed and that’s going to improve the uptime. What does that mean for volumes in ’24? And does that simply means less downtime? Can you qualify what that downtime is that we’ve avoid it? And I’ll leave it there. Thanks.
Lee Tillman: Yes. Well, maybe to start off with the decline question. I mean, our nominal decline in E.G. is about 10% per year, so that’s really where we land. There’s no doubt that an Alba infill program will help mitigate some of that decline. It’s probably too early to talk about the contribution and the amount of offset until that program is fully defined and ultimately funded by the partners. With respect to the turnaround, that’s really a triennial turnaround. It’s very comprehensive. It occurs usually every three to four years. It’s both onshore and offshore, so it’s a very comprehensive turnaround. And really, that’s protecting uptime performance that’s already world class at E.G. LNG. This is recognized as one of the best operating, most reliable facilities globally in the LNG market.
And we’re really investing to continue to protect that exceptional uptime performance that that team delivers really each and every year. And so this really is that investment. And it becomes even more important as we transition into this commercial phase where we’re going to be leveraging much more heavily global LNG prices through the Henry Hub. So it’s very fortuitous. It’s beginning that turnaround done during low gas prices and while we’re still linked to Henry Hub contracting.
Mike Henderson: Yes, Clay, I’ll speak about a little bit more color. We’re looking at 99% plus uptime there from the facilities in E.G. So as we pointed out, it’s really about protecting that uptime as we get into next year specifically.
Unidentified Analyst: I appreciate it, guys. Thank you.
Operator: Our next question comes from Neal Dingmann from Truist. Please go ahead with your question.
Neal Dingmann: Hi. Thanks for the time. My first question, maybe for Lee or Mike, just on Ensign, just wondering now that you’ve operated the asset for just a brief time. Can you speak to any thoughts or changes on how you think the asset will compete for capital versus the legacy assets? Both are good, so I’m just curious how they’ll compete.
Mike Henderson: I mean, obviously, super, super happy with how the integration’s gone, ahead of schedule, no surprises, everything’s positive. You saw the well results that we put at, I think it’s in Slide 12 of the deck. Top- decile performance there on oil basis within the basin. I think it’s a little bit too early to say in terms of a view of what that does from a capital allocation perspective. But I think first impression is very, very positive, and if we are going to be doing anything from a capital perspective, it feels like we may be allocating more in the future, but a little bit early just to get too definitive on that.
Neal Dingmann: forward to see what you can do with it, Mike. And then, second question just on OFS inflation. I’m just wondering if you could speak to any potential — not only potentially some softness that some others have spoken about, but any specific areas, either domestically or E.G. that you might be seeing.
Mike Henderson: Yes, I’ll take that one again, Neal, maybe just start with a reminder. Our 2023 guidance, we did incorporate about 10% to 15% inflation compared to 2022. And what we were assuming was the cost environment through 2023 would be comparable to the fourth quarter of 2022. We didn’t assume any deflation over the second half of the year. We did assume a little bit of moderation in steel pricing, which we’re actually starting to see. What I’d say we’re seeing at the moment is maybe a general flattening or plateauing of service costs. What we are definitely seeing is the access side. That has definitely improved. And that could potentially lead to maybe some improved pricing later in the year. As I look at the specific or the larger areas of spend, start with maybe rigs, I think we’ve all seen the softer guidance and activity that the publics have come out within the second quarter again, could lead to some modest softening in the rig rates later in the year.
Pressure pumping market access certainly improved, but I still think it’s a little bit early to make the call on where rates potentially go in the second half of the year. And as I mentioned, steel pricing is definitely trending lower there, and that’s pretty consistent with just the general softness that we’re seeing in all of the commodities. One point I would make is with the improving market access situation and the contracting flexibility that we’ve got in the second half of the year, we’ve actually already been able to hybrid in a few areas of the business. So for example, we get more experienced crews, we’re getting better equipment. That was something that couldn’t happen five, six months ago. So I’m pro with painting a somewhat positive trend there.
I would just caution, it does feel a little bit too early to be counting in deflation in the second half of the year. I think, particularly just when you think about the volatility of the backdrop that we face at the moment.
Lee Tillman: Yes, I think that, if I could just jump in, Neal. I think that we intentionally left commercial and contractual flexibility in the second half of the year such that we would have the opportunity to take advantage of any softening in the market. However, we took no credit for that within the budget. So as Mike said, our budget fully reflects inflation across the full year. So if we were to see more softening, that would certainly be perhaps a bit of a even a tailwind in the second half of the year.
Neal Dingmann: That’s great detail. Thanks, guy.
