Jay Allison: In fact I think the slowdown is a positive in the Western Haynesville. We — as Dan said earlier, most of the wells we’ll be drilling now will be two wells per pad. We have been drilling one well per pad. I think it lets our land group now get ahead a little bit for ’25 and ’26 because we have added a lot of acreage within a small window. I think it lets us position our wells better in ’24 and ’25 to de-risk a lot greater swath of acreage with fewer wells. So it really has been — the slowdown has served our land group well. And as Roland said, and Dan will tell you, it has not impacted really the drilling. I do think we’ll add another rig in ’25 like we were going to do in ’24, but the results will speak for themselves.
And so far, the results have been really good. They’ve been stellar for the acreage that we have. And the area that we’ve de-risked, which is probably from the hill to our northern well, probably 23 or 24 miles, we’ve said that publicly. We’ve got a lot of acreage we’ve derisked there, so it looks good. And I think this environment is favorable for us to slow that down.
Jacob Roberts: Thanks for that. My second question is around the leasing program that seems to have bled over from ’23 into 2024, and it’s pretty heavily focused in the first quarter of the year. Can you just provide any detail on what caused some of those conversations to fall into this year? Has the process become more competitive? And then maybe, if you can, a sense of the scale of the remaining transactions in the pipeline. Thank you.
Daniel Harrison: The process definitely has not become more competitive with the weak gas price environment. But — we’re leasing from lots of different parties. It’s a — there’s lots of reasons why you don’t actually close something you’re working on, so it’s not. I don’t think there’s any significant trend there. But we are kind of rounding up where we’ve captured a lot of the acreage in the areas that we think are the most prospective for the play. And so that’s really driving the program more than anything else, so just we’re finishing up.
Jacob Roberts: Great. Appreciate the time.
Jay Allison: We’ve stated that we average about $550 an acre, and in fact, at $1.61 gas, which is where we are right now, which I don’t think I’ve read it, we hadn’t been this low since spring of 2016, so eight years, I can promise you there’s no competition out there at $1.61 at all.
Operator: Thank you. One moment for our next question. And our next question comes to the line of Bertrand Donnes from Truist. Your question, please.
Bertrand Donnes: Hey, good morning, guys.
Jay Allison: Good morning.
Daniel Harrison: Good morning.
Roland Burns: Good morning.
Bertrand Donnes: This one might be a little bit weird, and I’m not saying it’s necessary, but if it did become necessary, is there any ability to negotiate with quantum on the minimum volumes? It seems like you guys have a mutual interest and even when they revert to 30%, there’s probably an interest in properly managing the asset instead of just kind of hitting a number that was inked at a different gas price, but it was purely out of curiosity.
Daniel Harrison: Well, that level is set so much far lower than our forecast and even our production level now. It’s just not even a question to give any thoughts to.
Bertrand Donnes: Sounds good, very succinct. And then, another one, just to keep them a little bit weird, is there — was there any consideration instead of technically suspending the dividend instead going to a kind of variable dividend? I just don’t know, management has a view on whether or not that has a place or no place or maybe it just doesn’t mesh with the corporate view.
Jay Allison: No, we didn’t consider that.
Bertrand Donnes: Sounds good. I appreciate the answers. Thanks.
Jay Allison: Great questions.
Operator: Thank you. One moment for our next question. And our next question comes from the line of Phillips Johnston from Capital One Securities. Your question, please.
Phillips Johnston: Hey, guys. Thanks. My first question is on your 3.5 times max leverage ratio covenant. At current strip prices, our model shows that you might be close to reaching that later this year, would you also see that as a possible risk, and if so, how easy would that — how easy would it be to get a waiver from the banks?
Roland Burns: We don’t see that. So we don’t think that we come that close to that, Phillips. So I think we just continue to monitor our spending level and not use much more of the credit facility.
Phillips Johnston: Okay. Sounds good. And just to make sure our models are calibrated. As we think about the five rig program, what would you expect the net well count to look like for the year in terms of both wells drilled and wells turned to sales?
Jay Allison: Ron’s got that number.
Roland Burns: Yeah, it’s in the press release too. Please read it there, yeah. I don’t have that email. Hang on. Give me two seconds. So as it says in the press release, we plan to drill 46 gross and turn — and that’s about 36 net wells and turn to sales 44 gross, 38 net.
Phillips Johnston: Okay. Sorry about that I completely missed that. Thank you.
Operator: Thank you. One moment for our next question. And our next question comes from the line of Leo Mariani from ROTH. Your question, please.
