Now it’s not just all Marcellus wells in our number because we have dry gas Utica wells in Ohio that are part of that averaging. But I think that one also should show up at the start of the year. And the only reason it would move around would be some well mix changes between the quarters.
Paul Diamond: Just one quick follow-up, actually speaking about that kind of choosing different areas for wells in Appalachia. How are you guys thinking about going to ’24, just more generally, but that mix between liquids versus gas through the year?
Clay Carrell: Yes. Our thought there is that it won’t be materially different than how we played out 2023, where we got the benefit of liquids pricing as gas was lower. We added some completions there when we came into the year. On the margin, that all moved around pretty evenly to where it was a change. I think it was 9 more wells to sales that we were thinking about in ’23 than what we had in ’22. But that would be the — could be the size of what a move there would be. We’re spending — roughly two-thirds of our capital in Appalachia is going towards liquids-rich wells and the other third toward dry gas. And I don’t think that split would change much.
Bill Way: And we apply strip against the development plan proposals that come in and economics drive the answer at a high level.
Operator: Our next question comes from Arun Jayaram with JP Morgan. Please go ahead.
Arun Jayaram: I wanted to see if I could maybe hair split a little bit with Clay on his outlook comments on 2024. Clay, if I heard you correctly, you mentioned how consistent with historical patterns, production would be declining a bit as you moved into the first half of the year, but the second half should be at similar levels to today. And I just wanted to — my hair splitting here is that the third quarter, you delivered 425 Bcfe of production and the fourth quarter guide is 410. So I just wanted to see if you — were you thinking about the second half being closer to the 410 or the 425?
Clay Carrell: Yes. So, closer to the 425 is what we’re guiding to there. And kind of the way I answered that other question, you’re seeing in that drop off from 3Q’s 425 to 4Q’s 410 the activity reductions that we applied to the year to navigate through the price cycle. And then, when you think about the cycle time on those Haynesville wells, which is a 5- to 6-month spud to turn in line, that’s where as we ramp production back up, our activity back up, that will start showing up in the second half of next year.
Arun Jayaram: Okay. That’s super helpful. And as you think about kind of lateral footage, I mean, you’re expecting flat kind of CapEx. Any sense of how much more footage you could do next year, given the pretty meaningful reductions in Haynesville costs?
Clay Carrell: Yes. We haven’t finalized the well mix and the order and all that yet. But I think in both areas, it can be in the order of 500 to 1,000 feet of longer average lateral length.
Operator: And our final question today comes from Noel Parks with Tuohy Brothers.
Noel Parks: I apologize if you touched on this before, but I’m just wondering, as you accumulated more data out in DeSoto Eastern part of your acreage from those first wells there. I was wondering any sort of refinements to your understanding, any surprises, anything that you’ve just been able to learn from a little bit longer performing data?
Clay Carrell: Well, if I fully understand your question, I mean, the learnings has been keeping mud properties in as good a shape as we can and trying to keep bottom hole temperature at the tools as low as we can, so that we could extend run times and get to some longer laterals in the play. That’s been what we’ve been working on operationally, and we’ve been continuing to have success in that space. As it relates to the well performance, we felt like it was going to be on the high end. It was part of our original acquisition evaluation, and it’s performed in line with what we would — we thought it would do. There’s varying flat periods across the acreage where some stay flat for a longer period of time, 4, 5 months, some stay flat 2 to 3 months before they start to decline. And so, maybe that’s some learning there. But overall, that’s kind of the main things that we’ve absorbed that we’re utilizing as we go forward to keep making improvements there.
Noel Parks: Great. That is interesting about just some of them having a longer flat period than others. Is that entirely geologically driven, or is there anything as far as just the rate you perform at or chokes you use that alters that as far as you know so far?
Clay Carrell: Yes. I think the biggest driver is the combination of the bottom hole pressure and the effectiveness of the completion and the continuity of the propped fracks that we put on the well and maintaining that continuity.
Operator: And ladies and gentlemen, this concludes our question-and-answer session. I’d like to turn the conference back over to the management team for any closing remarks.
Bill Way: Thank you all for joining the conversation on SWN’s performance today. We really appreciate it, and we look forward to you joining again as we continue to deliver shareholder value on a sustainable way. You all have a great weekend. And we’ll talk soon. Thanks.
Operator: Thank you. This concludes today’s conference call. We thank you all for attending today’s presentation. You may now disconnect your lines, and have a wonderful day.
