Ezra Yacob: Yes, Leo, this is Ezra. That’s a great pickup. It’s a good question because that’s exactly what’s happened is that it is raising up with respect to the returns and the way they compete for capital. Over the last couple of years, kind of coming out of the pandemic, we’ve reduced our — there. And the result of that, we’ve been trying to right-size the investment. The result has been really back to back years of the highest drilling — rate of return drilling programs that we’ve seen in the history of developing that asset. As everybody knows, it’s a very high-margin oil play where we’ve got a lot of infrastructure and a tremendous amount of industry knowledge there. Simply, the asset now is commanding a lot more capital investment this year.
We are looking to invest to maintain flat production, as you said. The production has decreased a bit over the last couple of years. And one advantage that we are seeing in the Eagle Ford, and Billy touched on this, and maybe I’ll let him add a little more color on it, is really how the inflation and service availability has manifested itself across these different basins and why the Eagle Ford’s a bit more attractive.
Billy Helms: Sure. As I mentioned earlier in some of the questions, obviously, you see more levels of inflation and more constraints on services in certain fields versus the other, the Permian being the most active play. Certainly, there’s a more constraints there on services and labor and those kind of things. So it allows us the opportunity to pick up activity in basins that are seeing less stress, you might say, and Eagle Ford certainly being one of those. On top of that, our team there in Eagle Ford has done just a tremendous job continuing to push innovation and striving for efficiencies such that we continue to make better and better returns in that play with time. And we’ve kind of reached a point, as Ezra mentioned there, that we want to maintain the constant level of production going forward in that play because we do see more than a decade of running room of continuing to maintain that production level with the opportunities we have in front of us.
So we think it’s just a good level of production to maintain going forward.
Operator: Our next question today comes from Neal Dingmann from Truist. Your line is now open.
Neal Dingmann: My first question is on your play detail, specifically, was looking at some other side. I see a couple of years ago, you all suggested you had approximately about 11,000 premium undrilled locations with about, I think, it was nearly 55% of these in the Delaware. Of that Del, about 40% of these will be in Wolfcamp plays. I’m just wondering if that really, number one, total premium locations is still — I forget what the last number you threw around the premium locations? And wonder if you’d still consider the majority of these in the Wolfcamp portion of the Del?
Ken Boedeker: Yes, Neal, this is Ken. I’ll take a shot at that. We — what we talked about earlier, and the way we really look at it, is we have 10 years of double-premium inventory at our current activity level. So locations really aren’t a concern for us. What we’re really trying to talk about and show is the value proposition of our 10-plus billion Boe resource base that has a finding cost less than our current DD&A rate. Investing in this inventory will use to DD&A and improve earnings and return on capital employed. Our well counts are really constantly changing as our development plans evolve, acreages swapped and laterals are extended. And all those changes improve our finding costs and returns and modify our location count. So what we’re really focused on now is lowering our cost basis as we invest at high returns.
Neal Dingmann: No, that makes sense. Then maybe Ken just follow up on that. I guess my follow-up is on play details, maybe specifically the Bakken. You all suggested, I think even a couple of years ago, it wasn’t a ton of locations, as you said, maybe I don’t know if you’d consider a ton of value there. So I’m just wondering how many — how you’d kind of look at that play today? And would you all consider — you certainly don’t need it financially, but would you consider monetizing it given it appears to be one of your more mature areas?
Ken Boedeker: Sure, Neal. The Bakken creates significant returns, and it is one of our highest percentage plays that we have in the Company. So where it’s appropriate and when it’s appropriate for development, which is we’re going to be putting some money into it this year, we’ll try to run about a one-rig program there the foreseeable future.
Operator: Our next question comes from Scott Gruber from Citigroup. Your line is now open.
Scott Gruber: So I saw in your supplemental debt that you mentioned that continuous pumping operations are helping to drive completion efficiency in the Delaware. I believe that’s one of the benefits you’re seeing for running your frac fleet. Is that accurate? And just a bit more detail on how continuous fracking is having completion efficiency above and beyond doing zippers?
Billy Helms: Yes, Scott, this is Billy. Yes, we’re thrilled with the — our efficiencies driven through our completion teams. The continuous pumping operation, you’re right, is tied to mostly our electric frac fleets. Just a reminder, we’ve — we’re probably running 60% or 70% of our frac fleets today are electric. And we’ve been in that business really since about 2015. So, we’ve been operating more electric frac fleets probably than most of our peers or most of the industry for a long period of time. And through that, we’ve gained a tremendous amount of knowledge of how to continue to drive efficiencies in that operation. It really has started more in our San Antonio group in the Eagle Ford play, and that’s why we’re so excited about continuing our investment there.
And certainly, we’re transferring that information and that those techniques across the Company, including the Delaware Basin. But basically, the continuous pumping operation allows us to minimize any amount of downtime, so we can increase the amount of footage we complete every day, which drives the well cost down over time and allows us to approach some really highly efficient completion strategies. And so, part of that is also leading to improved completion designs, which is allowing us to make better well performance. So overall, it’s just one thing that builds on another, and we’re excited about the future and where that takes us.
Scott Gruber: Got it. And then you also mentioned taking advantage of any softening in — frac rates if they do manifest this year. How is your contract coverage for both currently following the period of tightness? Would you be able to capture any deflation before year-end? Or would that really benefit more at ’24 just given contract coverage?
Billy Helms: Our contracts are really staggered, and they don’t all roll off at any one given time. Certainly, our well cost is up this year as I mentioned earlier, because some of those contracts have rolled off last year and renewed on those higher day rates and pumping charges this year. But in general, we have about 45% of our drilling rigs secured under term agreements and about 65% of our frac fleets. So that leaves us ample opportunity to capture opportunities if they do present themselves as time moves on.
Operator: Our next question comes from Jeanine Wai from Barclays. Please go ahead.
Jeanine Wai: My first question, maybe following up on Leo’s question, on the Eagle Ford. In terms of the step-up in activity in the Eagle Ford this year, can you talk about how capital efficiency compared between the overall Delaware and South Texas Eagle Ford? I guess when you pull the well data, the difference in the well performance looks like the Eagle Ford is about 30% lower on a cumulative oil per foot basis over the past couple of years, but that’s only one side of the equation, and we realize that. And I think your 3Q disclosure indicated that the Eagle Ford well cost is almost 30% lower on a per foot basis than in the Delaware. So I guess just putting it all together for us, can you just provide some color on how capital efficiency and returns compare between the Eagle Ford and the Delaware?
Billy Helms: Yes. Jeanine, this is Billy. Happy to give you some color on that. The Delaware Basin is certainly one of our most capital-efficient plays, quickly followed by the Eagle Ford. The advantage we have in the Eagle Ford is, as I mentioned earlier, the tremendous efficiencies that have been driven in that play. You’re right the cum per foot is probably a little bit lower in the Eagle Ford but the well cost is also significantly less. And so we can put a lot more wells to sales in a lot shorter time frame than we can in the Delaware Basin. And then going back to that also, we didn’t really feel that we wanted to ramp up activity anymore in the Delaware Basin, but instead leverage on our multi-basin portfolio to increase activity in areas where equipment and crews are more available to leverage into our operation.
And so that’s what we’ve chosen to do. But I think the Eagle Ford is still one of our most capital-efficient plays we have in the Company, and we’re excited about that opportunity to keep sustaining volume going forward.
