Nitin Kumar: Why don’t we go back to the Delaware for a minute? As I look at your slides, and there were 2 things that you were doing in the Delaware this year. You were also increasing the mix of your Wolfcamp oil in the drilling schedule and then there were the enhancements that you made. Could you break out the improvement that you’re seeing between the mix and then the new technologies that you’re talking about?
Jeff Leitzell: Yes. This is Jeff. The first thing I’d say is in the Delaware, our technical teams, they’re doing an outstanding job of continuing to build on their understanding of the subsurface geology, their geologic models. And really what they’re focused on is increasing the value of each of our development units by maximizing and improving the overall NPV. So really, we look at it from kind of a total bench standpoint when we go into development. Now when we’re looking at productivity and you talk about that, the wells are looking outstanding and we’re kind of seeing a marked improvement year-over-year. We’ve seen good increase in productivity across the majority of our benches, and really the Wolfcamp as about a lot is kind of leading the way due to that new completion design.
But the one thing that we always want to go ahead and highlight is, we have a large acreage footprint, over 400,000 acres. We’ve got high number of unique targets that we co-develop based off the very unique geology in each one of these areas. So you’re going to see when you look at individual well results or even roll-up for the play, you’re going to see that quarter-to-quarter variations in productivity and well performance. But ultimately, we’re really happy with all the results that we see and it’s hitting all the expectations and we have all of that built into our forecast.
Nitin Kumar: Great. I guess the reason I’m asking this question is one of your peers in the play has talked about improving recovery rates, not just optimizing the well but actually improving recovery rates with the application of technology and they’ve talked about 20% gains. So I guess, given your experience in shale and, of course, your track record, I’m curious to see if you have seen technologies or are seeing technologies that could help that recovery factor increase not, just optimizing the wells but really a step change in what you’re drawing from the rock.
Billy Helms: Yes, Nitin. This is Billy. Let me give you a little more color on that in general. As far as the recovery factor, we’re constantly improving or working to improve the long-term recovery in all of our plays, and it’s something that goes really back to the foundation of the company and is something historically we’ve done, as you mentioned. We leverage a lot of technology to help us understand how we’re targeting those plays and how we’re completing each well. And so it involves a lot of things. And let me just talk about that in the sense of how we think about it. I mean, these unconventional plays, the completion efficiency is really important how we evolve over time. And so just thinking about how we’ve applied new technology, it goes back several years where we talked about the frac design itself, how we change the way we attack the well from the type of sand we pump, the spacing of the perforations, the cluster spacing, the frac rate, how we target reservoirs, our understanding geologically of how we understand the best place to place the target so we can co-develop like zones and those kind of things.
So that evolution over time has caused us to see dramatic improvements in production, which is a proxy for a recovery factor over time. And the most recent example is, this is what Jeff just talked about, the improvements we’ve seen in our Wolfcamp play. And you can readily see, the 20% uplift we’re seeing in completions in production performance is due to the completion approaches. So all those things over time lead to improved recovery factor.
Operator: Next question comes from Josh Silverstein of UBS. Please go ahead.
Josh Silverstein: Just on the updated 70% shareholder return level. How are you thinking about excess free cash flow beyond this? Will you look to increase the exploration budget, or could you, in theory, increase the shareholder returns to 90%? Any thoughts would be helpful here just to get the cash balance can keep growing substantially next year and there’s no maturity until 2025.
Ezra Yacob: Yes, Josh. This is Ezra. Ultimately, I think the answer to your question is that 70% is a minimum hurdle. In the last couple of years since we first came out with the initial cash return guidance, we had a minimum cash return commitment of 60%. In 2022, we were at 67%, and this year you see that we’re on track to be north of 70%, probably closer to 75%. So I think that’s the way you should be thinking about the guidance on there. And really, the big thing with our free cash flow commitment, it’s a minimum of that 70%. But again, it’s really founded in and hopefully, it doesn’t remove the focus from our regular dividend. The regular dividend, we feel, is the best indicator of a company’s ongoing performance, the improved capital efficiency going forward.
And it’s a commitment that we give to our shareholders based on our ability to continue to lower the break-evens and expand the sustainable future free cash flow generation in the company. It’s backstopped with a pristine balance sheet. And in this quarter, when we raised it to 10%, One of the ways that we raised is by looking at what does it take on a breakeven there. And as we talked about before, we can support this new $2.1 billion regular dividend in commitment. At a range of maintenance CapEx scenarios, the higher end of that range would be with a $45 WTI price. And when I say a range of maintenance capital scenarios, let me be clear when I say that. For a company like ours that has multiple basins, differing amounts year-over-year of infrastructure spend or exploration, different product types.
We look at maintenance capital through the lens of what does it take to keep production flat for a 5-year period, but also across those different investment scenarios. Are we investing in the health of the company longer term with exploration or are we really just narrowing it down to just a focus on maintaining production? And so we end up with basically a range of maintenance CapEx between $4.2 billion and $4.8 billion and so a midpoint of about $4.5 million. And as I said, at the higher end, that’s where we can maintain that level with the $45 WTI.
Josh Silverstein: Got it. And last for me. As you guys are thinking about the portfolio, how are you thinking about any kind of long cycle or conventional opportunities like Trinidad to kind of add in relative to bringing on some additional unconventional growth opportunities? Thanks.
