David Deckelbaum: Good morning, Tom and team. Thanks for taking my questions. I wanted to ask maybe a little bit of just a cost benefit analysis. You guys have been beating production now steadily largely on what appears to be cycle times and just finding ways to do things faster in the field, which is quite commendable. I think you guys articulated the benefits of cost savings on things like the Windham Row in the 10% range. As you get better with some of the smaller projects, how do you think about that balance versus larger project savings? Or should we think that even with some of the faster accomplishments that you’ve achieved with smaller developments that you would be able to exponentially improve upon that as you get to larger developments?
Blake Sirgo: Yes, David, this is Blake. I’ll take that one. I think it’s important to iterate cost is an output of our decision-making. And so while lower cost really helped drive some of our economics, we are focused on total returns of our projects and the highest PVI. And so, if that ends up being a three-well project in Lea County versus a 54-well project in Culberson County, we go where the PVIs tell us to go. And Obviously, continued cost gains really help. Cycle times really help, but it doesn’t drive where the rigs go. It really drives us that full economic analysis, and that’s what we lean into.
Thomas Jorden: An example of that, I love what Blake said, the cost isn’t a first order driver. For now and again, we’ll have a project either underway or soon to be underway. And our teams through additional science analysis, we’ll propose spending more on completions on a project and drives the cost up. But we always look at the incremental benefit financially and make the best decision we can. We learned — we all learned early on that you can’t save yourself rich. You have to create value.
David Deckelbaum: I appreciate the color on that. Maybe just pivoting to the Marcellus, a similar line of questioning on just how you thought through deferring completion activity versus curtailing existing production and keeping up with the completion kins, if there is sort of the inefficiency of drilling programs and frac crews that gets lost in that process or how you guys approach that sort of thought train?
Blake Sirgo: Sure. This is Blake. I’ll take that one. Yes, it absolutely is a trade-off, you’re spot on. Our preference is to run a frac crew continuously. We know that’s when we get our best efficiencies. But once again, it’s back to that investment case and what are the economics of the project. And while that might give us better efficiencies, given where gas prices are, we just can’t have that level of investment in the Marcellus right now. We need to slow down. We need to throttle down. And so that does mean usually giving up a little bit of efficiency but that’s still the prudent capital decision to make, and that’s why we’re doing it.
Thomas Jorden: I want to give a little different spin on an answer here, David. The Marcellus is a great operating area, and we are very constructive on natural gas prices. But I’m also going to tell you that, as you know, we’ve reentered a part of the field that hasn’t seen drilling over time. And we’re very pleased to be doing that. And this just gets to my being a responsible operator and communities we operate. Susquehanna County, 20 years ago was one of the Forest Counties in Pennsylvania. And because of the resource development there, that county is thriving. And there’s a whole group of landowners that have participated in that because been ahead of an area we are precluded from drilling it. And so we want to be really thoughtful before we just defer completions there. And we’re going to continue to have an ongoing activity and not that we’re going to be financially reckless because we won’t. But our impact on the community is part of our decision-making.
David Deckelbaum: Thanks, Tom. Thanks, Blake.
Operator: We’ll go to our next question from Scott Gruber at Citigroup.
Scott Gruber: Yes, good morning. Tom, long-dated gas because they have been moving higher on all the data center growth excitement, how would you think about capital allocation between Anadarko and the Marcellus, if the forward curve is right, and we’re in the $3.50 to $4 range, in late ’25, ’26? And oil is still healthy, call it, in the 70s. How would you think about that allocation?
Thomas Jorden: Well, I wouldn’t have to thank very hard. I’d look at the incremental economics and we go where the best economics are. We have tremendous gas resources in both basins. The — and Anadarko has natural gas liquids, which really provides an economic boost. But the Marcellus has amazingly low cost of supply, and we produce pure methane, which we just have to compress and put into an air state line, so — or a pipeline. And so we would look at the economics. I think if we were — if some of the promise comes through on the increased need for natural gas and electricity generation, you probably see us increase activity in both basins and also seek creative long-term contracts that might give us exposure to electricity pricing. Blake, you want to comment on that?
Blake Sirgo: Yes, sure. I mean we’re all learning this AI power demand story together, and there’s a lot of unknowns, but there’s a lot of excitement the power gen that’s going to be required is huge. Lots of it looks like it’s going to come on the East Coast. That’s very proximal to our asset. There’s a lot of existing pipes there that we can easily get our gas to those markets. And we’re very interested. We’re talking to a lot of these folks directly trying to understand their business and their needs, and we will be ready to participate.
Scott Gruber: It’s exciting. We’ll wait for a word. And then just turning back to Windham Row. Just curious, you mentioned doing simul-frac on half the wells. What’s the limitation there, why not doing on all the wells? Is it comfort with the technique or tag configuration or scheduling the frac crews? Just some color on the limitation there? And if there’s any upside to doing it on more than half?
Blake Sirgo: Yes, Scott, it’s Blake. I’ll take that. That’s a great question. And I think it’s something that gets missed sometimes in simul-frac is you really have to have an optimal pad with a lot of wellheads on one pad to optimize the cost savings. There is sometimes where you might some frac and save no money because a simul frac crew is just basically two frac crews smashed together. So you’re paying a lot of money for that crew to be there. The efficiencies come when you have a lot of wells on one pad. And just the layout of these drill spacing units doesn’t always give us enough wells per pad to use some frac optimally. So it’s back to that whole cycle analysis. The goal is not to simul-frac everything. The goal is to make the most economic wells. And so we’re only chasing it where it makes sense.
Scott Gruber: Well, I appreciate the color. Thank you.
Operator: Our next question comes from Neal Dingmann at Truist.
Neal Dingmann: Good morning, Tom. Thanks for the time. My first question comes for you or Blake, maybe on inventory, specifically. Looking at Slide 5, you had an interesting comment that I think makes a lot of sense, and that’s you all suggest that the total fluctuates based on things like well spacing cost, cadence and the like. And I’m just wondering how aggressive or conservative would you consider your estimates versus what you’ve seen play out in the trends in recent quarters?
Thomas Jorden: Well, I’ll just say, we have future landing zones that are not modeled in that inventory. But we want to be very careful with how we talk about inventory. And when I say that, I mean, we want to deliver what we promise. And so we don’t throw the kitchen sink in, although our inventory today has zones that we didn’t have in our inventory a few years ago. There are still zones to be tested, both shallow and deep. And we’re pretty optimistic about our ability to extract maximum value out of an acre of land. But the inventory we published is one that we think we can deliver.
Neal Dingmann: Very good. And then just a second question on capital spend. Specifically, I noticed what I think now what is about 70% of CapEx is directly from Upper Marcellus. Is this a result of just productivity that you highlight on Slide 19 or what’s driving the spend in this upper area?
Blake Sirgo: Well, we have some great upper locations in the field. Our Tier 1 uppers really long lateral lengths, competitive economics. And so they’re just competing for capital. But also the upper is the future of the assets. So we’re — we like having activity in the upper. We’re still learning about it. We’re still trying to understand our well spacing and our frac design. And it’s important, we continue projects in that zone.
Neal Dingmann: Thanks, Blake. Thanks, Tom.
Operator: We’ll go next to Derrick Whitfield at Stifel.
Derrick Whitfield: Good morning. Thanks for your time.
Thomas Jorden: Good morning, Derrick.
Derrick Whitfield: Tom or Shane, a bit of a build on an earlier question. If gas prices were to continue to underperform throughout 2024. How would you weigh or evaluate the decision between reallocation of CapEx and increased return of capital? I suspect your Anadarko and Permian teams would like more capital.
Thomas Jorden: Yes. You’re saying the Marcellus pricing stays kind of in and around where it is like this through the rest of the year?
Derrick Whitfield: That is correct.
Thomas Jorden: Yes. Well, look, here’s what I’d say is we do build in a lot of flexibility into our capital planning. And a couple of that’s really foundational to that and a couple of things. One, some plans to accelerate if market environment changes and things get better and also to decelerate if they deteriorate or, in this case, don’t firm up a little bit. I think the second element is we don’t engage in a lot of long-term contracting. And that’s really what gives us the flexibility to make those adjustments as we go. And I would say we maintain that flexibility as we get to the end of this year and into next year, if that’s what the market signals say, and that’s what translates through into the economics. We certainly have a great set of inventory that we just talked about throughout the portfolio that would have a call on, on capital if prices remain like this for an extended period of time.
Derrick Whitfield: As my follow-up, regarding the deferred training lines in the Marcellus. How long would you technically be comfortable in deferring the wells before you’d be concerned with compromising the effectiveness or integrity of the completion?
Thomas Jorden: Yes, we’ve looked at that long and hard and we don’t see a degradation in shut-in time. There’s a history as you go back a decade of fairly significant shut-ins. We don’t really have a time clock attached to it. But I — we’re anticipating turning these wells online later in the year. And we’re — our data tells us that those reservoirs will not suffer because of it. And part of that is because we don’t produce much water there. And so you don’t really have the issues that you might have in the other basins.
Derrick Whitfield: That makes sense. Thanks for your time.
Operator: We’ll go next to Leo Mariani at ROTH MKM.
Leo Mariani: I wanted to just dive in a little bit more to CapEx here. I wanted to kind of get a sense on sort of how the numbers are trending. See second quarter CapEx is going higher, do you expect CapEx to kind of come down a little bit in the second half versus the first half, is kind of second quarter, potentially the peak here and — when you talk about flexibility in the program, I know you mentioned a couple of times, potentially room for more activity. Is that more just kind of a function of some of the savings you’ve seen year-to-date?
Shane Young: Yes, Leo, thanks for the question. And look, there’s a couple of things I would just point to, one, Hana put together a great slide, a new slide in the deck, in the Appendix 33 that sort of shows where some of the activity is over the course of the year. And your point that you just made around, does it feel like the second quarter could be a peak capital quarter and then the back half of the year, if you take the residual and divide by two, that may be a lower number than that. And that sort of bears itself out, I think, on this page. So I don’t — yes, I think you’re interpreting the data the right way in terms of what the pace could look like for 2024.
Leo Mariani: Okay. I appreciate that. Then I just wanted to follow-up a little bit on kind of Upper Marcellus. As you look out the next couple of years, do you see the Upper Marcellus becoming kind of increasing percentage of your overall Marcellus activity. Is that going to be just kind of driven by somewhat the depletion of the Lower Marcellus in the inventory stack here?
Blake Sirgo: Yes, Leo, you nailed it. It’s — the Lower Marcellus has been a wonderful zone, and we know all the remaining sticks, and we plan on drilling them here in the next few years. And the remaining is all the Upper. That’s the future of the asset. And so as we are chewing through our lower inventory, you’ll see more upper come in each year. We’re really focused on testing and delineating the upper and just proving it out. But yes, depending on capital spend, the Upper will be a bigger and bigger portion of our program.
