We don’t get over our skis on that. We try to push our teams to model the most recent operational efficiencies and then we drive them crazy trying to get better. But production is not the input, it’s the output of good, solid capital allocation.
Neal Dingmann: Great point, Tom. And maybe just a second along that same line, I’m just wondering, look at the slide that talks about the gas production. I’m just wondering, is it fair to say that, you maybe have seen peak production or is it just what you’re forecasting that are just a basis of what’s going on with prices and that’s going to be an ultimate driver?
Tom Jorden: Yeah. It would not be fair to assume anything from our projection other than it’s our current look at an uncertain future. We say that we have contingency plans. If gas prices really recover, as we hope they will, within our capital guide, we have plans to get back to work this year and set ourselves up for nice growth over the next two years. That’s not a plan, but it’s on the shelf ready to go.
Operator: Our next question will come from the line of Michael Scialla with Stephens. Please go ahead.
Michael Scialla: Hi. Good morning, everybody. I just wanted to ask about your return of capital. Obviously, way above your target for the year, but even with the bump in the dividend in the fourth quarter, it looks like you slowed that a little bit. I wanted to ask about that and then also the decision to bump the base dividend when you had been leaning more toward the share buybacks when you pulled back on the variable dividend. Why the bump in the base dividend rather than buying back more shares?
Shane Young: Hey, Mike. Shane here. I’ll take those two questions. Look, on the buyback, we remained active in the market during the quarter, but we were a little bit cautious. We were trying to kind of get a gauge whether winter and weather would materialize, and I think, as it didn’t, we decided to carry some of that cash over into year end. That’s why you saw the cash balance build up to around a $1 billion, which really puts us in good shape in what looks like it could be a soft gas market in 2024 to be a bit more aggressive on the buyback. So, yeah, there was a little bit of a timing element to that, I would say. On the base dividend, listen, in addition to the commitment to deliver 50% plus of our free cash flow to shareholders on an annual basis, we also remain committed to increasing the annual dividend responsibly on an annual cadence.
5% feels like a pretty good lift, but not overly excessive. So we’re happy with the 5% bump, and we get into next year, we’ll evaluate it again. If it makes sense to do it, we would expect to continue to do it on an annual cadence.
Operator: Your next question comes from the line of Scott Gruber with Citigroup. Please go ahead.
Scott Gruber: Yes. Good morning. Through your row development program, you’ve been able to push down your Delaware cost to several $1,100 a foot. As you’re reengaging in Anadarko, do you think you’ll be able to work down the cost structure into play? Are you thinking about pad size or rectifying operations or any other actions that you may need before you push down that $1,300 figure?
Blake Sirgo: Yeah. This is Blake. I’m happy to take that one. Yeah. We think there’s always room to push our efficiencies further and we do share a lot of our learnings across basins. But at the same time, the Anadarko is a different basin than the Permian. So it’s deeper, it’s higher pressure, the drilling can be more difficult. And really what we’ve seen from our Anadarko team is we ran a real consistent program in 2023, so consistent drilling activity and our crews did what they always do, they got better at it, and we saw our costs come down and get more in line. They’re already taking advantage a lot of the same pad efficiencies we see in the Permian. But if we saw opportunities to enlarge projects and get more economies of scale, we’ll absolutely take advantage of those.
Scott Gruber: Got it. And you guys have stuck with an estimate of about 5% deflation in service costs and material costs. But we’re now seeing several operators obviously take actions to reduce activity in the Marcellus. Do you think you’ll be able to see additional service cost savings on top of that 5%, especially in the Marcellus on your remaining activity?
Blake Sirgo: I mean, I sure hope so. The — we’ll see how the market plays out. They’re typically when more services become available, it does drive pricing down. We’ve been very strategic how we’ve gone into 2024 with our contracts. We’re very, very lightly contracted and that’s by design, so we can take advantage of any downswings. But at the same time, you know, who we work with and making sure we have premium service providers that share our safety culture and our drive for excellence is really important to us. And our service providers need to make a return also. So we’ll be working with them closely, and if there’s continued movement in the market, we’ll be there to take advantage of it.
Tom Jorden: But I don’t want that point to be lost. One of the reasons we have such flexibility in our capital allocation is because we’ve worked really hard over the last couple of years to have a great set of vendor partners and a very light amount of long-term commitments. So we really do have a lot of flexibility in both our drilling and completion services to pivot from one basin to another.
Operator: Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners. Please go ahead.
Kevin MacCurdy: Good morning. First, I want to say we appreciate the three-year outlook. I think you’re one of the few companies in your peer group with the confidence in your inventory to provide a detailed multiyear outlook. My first question is on that outlook. Are you assuming a similar capital allocation in 2025 and 2026 as in 2024? And under that scenario, when and at what levels does the Marcellus start to flatten out?
