Doug Leggate: I appreciate the new breakeven number, Ezra. That’s very helpful. Thank you. My follow-up is on portfolio evolution because, I guess, we all know that 10 years is not the number, I guess, for EOG. But yet your slide deck continues to refer to 10 years of double premium. So if I assume that’s dominated by the Eagle Ford and the Permian given that you’re happy with that level of activity, how does it evolve if the next leg of growth is Dorado, Utica in terms of mix? And I guess what I’m really driving at is, our channel checks on midstream suggests you could potentially be drilling north of 300 wells in the Utica in 2026. Does that sound reasonable to you in which case, what’s the implication for mix?
Ezra Yacob: Yes, Doug, I’m not going to speculate on 2026. As Billy said, it’s a little bit early to be speculating on 2024. What I’d come back to is our disciplined base of investment. We have a lot of flexibility in the Utica. Specifically, we’ve got over 90 or roughly 90% of the acreage there is held by preexisting production. We only have a minor drilling commitment there. So we’re in a great spot where we can actually develop that asset in a disciplined ability to increase activity commensurate with the increase of our learnings. Now overall, your question is recently our exploration efforts have yielded very high return, more combo plays, or in Dorado case, a gas play, and that’s true. And there’s something to be said for that.
Our exploration and emphasis, I would say is dominantly more oil-focused because the margins are a bit more forgiving on oil from what we see. But ultimately, with our premium investment hurdle rate, and that’s at bottom cycle pricing of $40 oil and $2.50 natural gas through the life of the asset, we’re somewhat agnostic to the product mix. Now it does require a heavy lift, by Lance, to discover new market potentials for us. And we continue to invest in different parts of the infrastructure and supply chain to lower our costs and lower our break-evens. But ultimately, we’re investing in high-return assets and we continue to build out the inventory in a high return framework. More than the 10 years of double premium drilling, I think I’d steer you towards the 10 billion barrels of equivalents overall that is, at a finding and development cost, lower than our current DD&A rate.
And as I said in the opening remarks, that contemplates maintenance levels at current levels of production, roughly 30 years of production. So we’re very confident in the high-return inventory that we put together and believe that it’s going to continue to deliver great shareholder value in the future.
Operator: The next question comes from Charles Meade of Johnson Rice. Please go ahead.
Charles Meade: Billy, I’m going to make one more run at the ’24 outlook. I think you’ve laid out that the activity levels are going to be pretty similar to ’23. If I look at or if I try to think about the big moving pieces, you’re going to have some efficiency gains, some capital efficiency gains, especially as some costs come down. On the other side, you have a slightly higher base production. So is it a reasonable stake in the ground to think that you guys can have similar results of ’23 in the sense of low single-digit oil growth and kind of low-teens NGL and natural gas growth?
Billy Helms: Thanks, Charles. Yes, this is Billy. For ’24, we’ve kind of said it’s a little early to get specifics about things. But I would point you to the fact that we’re running at a pretty decent level of activity now. We’re going to maintain that same level of activity going into next year. Now just a reminder, we’re spending about $6 billion on our CapEx program this year, and it has proved to be fairly ratable through each quarter of the year. Similar levels of activity, there will be some upward movement maybe on efficiency gains. Like you said, we’ll have a little bit more efficiency gains to factor in maybe some cost reductions due to casing cost, those kind of things. We’ll still have some infrastructure spend. We may drill a few more wells in the Utica and Dorado plays.
And we’re trying to quantify that as we go towards the end of the year. But directionally, that kind of hopefully points you towards what next year might look like. We’re not going to see a big ramp up in activity in any play as we see today, small changes in capital efficiency and well cost as we go into next year, we have some infrastructure spend.
Charles Meade: Got it. Thank you, Billy. And then, I’m not sure who this would be best for, but I’m curious about your 3-mile laterals in the Utica. It seems to me like you’re pleased with the results because you mentioned that you’re even considering longer laterals in the Utica. But curious if you could address that point? And then also whether we can expect to see 3-mile laterals in other key plays for you guys? And if yes, where, or if no, what’s special about the Utica that it works there and not in other places?
Billy Helms: Yes. Charles. This is Billy again. Let me give you kind of an overview and then Jeff may add some more color. The 3-mile laterals in the Utica, yes, we’re very excited about that play and its ability to do these longer laterals very efficiently on the operational side. We’re drilling these things in record times and making progress with each pattern of wells we drill. And we feel we have line of sight on being able to continue to reduce cost over the longer-term period as we apply learnings from other plays into this area. So that’s going to continue. Now we’re also drilling longer laterals in some other plays. We’ve drilled some 3-mile laterals in the Eagle Ford and we’re drilling 3-mile laterals in the Delaware Basin. So we expect that trend to continue in each of our plays. Now Jeff might want to add some colors on what we’re seeing on performance there, too.
Jeff Leitzell: Yes. Just a little bit to add in. In the Delaware, in the Eagle Ford and in Utica, we’ve had great operational efficiency with our 3-mile laterals. And that’s one of the things, as you start stretching out the length of these laterals, you want to make sure that operationally you don’t have any issues on the drilling side and you’re able to optimally complete that. And we’ve seen really, really good results with that. The other thing we’re also seeing is by drilling these longer laterals, we’re able to supplement 1 vertical with a 3-mile lateral versus 2 verticals and a 2-mile lateral. So we’re able to see substantial cost savings there anywhere from kind of 15% to 25%. So we’re definitely excited about where we’re seeing it. Obviously, it ties in with our leasehold, and we have to see where we can actually drill 3-mile laterals. But we are looking to expand that across our plays moving into next year and beyond.
Operator: The next question comes from Scott Gruber of Citigroup. Please go ahead.
Scott Gruber: The enhanced completion technique in the Delaware appears to be a success, if I heard correctly, 20% uplift in productivity. But there has been a question regarding applicability as you’ve talked about in the past. What’s your latest thinking on how widely applicable the technique is across the play? And will there be an increase in the number of wells completed with the technique next year?
