Bertrand Donnes: That’s a really good point. The other question just maybe around the Jones transaction That’s a really good point of that. The other question, just maybe around the Jones transaction, could you maybe go into how that came together? Where they ready before you found the acreage? Was the acreage part of the push to maybe get the agreement? I don’t know, should we expect more cowboy cash in the future or is this kind of a onetime thing?
Roland Burns: I think come August, it’ll be four years that we have been had a group of landsmen leasing acreage in this area and we kind of set the boundaries. As those boundaries have expanded, we’ve looked at where the kind of the north, south, east, west sides are and you work all those sides to come in inward. It just happened that this year, in 2024, we were able to pull off several of the larger transactions. We did that in 2022. That was a big acquisition in ’22 that we made. We picked up the Pinnacle plant in that 145-mile high-pressure pipeline. And then this year, we’re able to close another acquisition. But I think, in our opinion, all of the major acquisitions that we would be looking at, they’re in our rearview mirror. They’re closed. And what we’re doing now with our land group is just kind of cleaning up. What we think we’ve secured all the parameters, which is cleaning up the infill.
Operator: Thank you. One moment for our next question. Our next question comes from Jacob Roberts with TPH. Please go ahead.
Jacob Roberts: Good morning. Maybe circling back to Derek’s first question, just thinking about the cost improvements on the core position over time. Wondering if you could speak to some of the levers that might be pulled in the Western Haynesville, that could also bring those costs down. Just looking for more specifics around, what we could expect to see to get those days to drill lower or cost lower.
Dan Harrison: Yes. We’ve got kind of two things working in the Western Haynesville. Obviously, the depth that’s deeper, the vertical hole section has a really thick Travis Peak section. We’ve made a lot of improvements with the bits that we’re using. Getting better ROPs through that section, which takes several days, that’s been part of the progress we’ve made. We have changed our casing design a little bit that saved us some time. We’ve also — and in the lateral, it’s really the temperature that we’ve said many times. We’ve had a lot of really big improvements that have allowed us to handle the temperature. We’re still making those improvements and that’s where we see the additional day savings moving forward from where we’re at today.
A – Jay Allison: We have seen that in the numbers. In other words, as we drill these wells, we have seen this cost improvement. We’ve also seen a lot of upside in our EURs. Both of those metrics are going in the right direction.
A – Ronald Burns: And Jake, the other thing I would add is, Jay mentioned and Dan, both, we’re currently drilling with both of our rigs on two well pads. In addition to the temperature being a key, the multi-well drilling pads should end up providing efficiencies like they do in all the plays as well.
A – Jay Allison: Remember, we started out drilling Bossier. As we said during this call, the four wells that we just put on, they’re Haynesville wells. You’re a little bit of a difference in drilling as you derisk both the Bossier and Haynesville.
Jacob Roberts: Great. I appreciate the color. Maybe staying on the same topic. I was wondering if you could comment on any variation in completion design that you might have pursued of the dozen wells or so that are online, and if you could offer any insight into what you think a full field development design might look like?
A – Jay Allisson: That’s a really good question. I’ll kind of start with the last question. Full field development, that’s, I’d say, we haven’t got too deep into thinking about that because that is down the roadways with the plan for us to drill out, basically just to drill out the acreage and get it held. We still have a few singles to drill, but we’re drilling as many two-well pads as possible. On the completion design, we have pumped a larger frac design on this last well that we turned to sales, the Ingram Martin, just a larger job. The perforation the cluster spacing number of personnel that was the same, but just a bigger loading, more water, more sand. We just wanted to get the clock started and see how that well is going to perform versus the first 11 that we turned to sales.
Nothing really too different that we’re doing on the completion design down here versus in the core. We’ll just kind of continue to get our production data and we’ll depend on what it tells us. We’ll see if we need to make any changes but right now, I think what we have works pretty well. We’re just not looking to do anything drastic right now.
Operator: Thank you. One moment for our next question. Our next comes from Atidrip Modak from Goldman Sachs. Please go ahead.
Atidrip Modak: Good morning team. Thanks for taking my questions. It seems like you moved to more spot frac fleets for the rest of the year. Can you provide any color on the cost savings flexibility that brings to your operations? Maybe touch on if there are any efficiency-related concerns or not associated with that?
A – Jay Allisson: We’ve dropped to the two rigs. We didn’t have a need for as many frac crews, one. But we did — it’s obviously a squeeze on the frac crews with the number of rigs dropping dramatically and we have obviously gotten some concessions on pricing just due to the frac activity and we’ve got a really good relationship with the frac provider that we got now. So that’s probably, I think, helped us a little bit with the pricing that we’ve been able to put into place for the rest of the year.
Atidrip Modak: Got it. Understood. And then as you think about the macro here for gas prices, any updated thoughts you can provide around capital allocation strategy and balance sheet management with the sensitivity to gas prices as you are seeing?
A – Jay Allison: Yes. We continue, of course, to monitor that and we’ve had we have not only fairly volatile NYMEX prices, but also spot prices that can be very volatile during the months, based on how much gas is needed and where. There’s definitely, we strategically do some shut-ins every now and then. It’s usually for a day or two if we don’t like spot prices. We’ll continue to be able to monitor that and react to that. We’ve delayed turn to sales, sometimes not to open them up in a spot market type scenario and wait for a first of the month type. We’ve tried to manage within the then to maximize the realizations in this really weak environment and continue to have the ability to change the amount of rigs we’re running.
