Nissa Darbonne, executive editor-at-large, Hart Energy: Hi. Thank you for joining us. I'm Nissa Darbonne, executive editor-at-large for Hart Energy. I'm visiting with Tim Beard. Tim is vice president of drilling for Expand Energy, the newly merged Chesapeake and Southwestern. Tim, thank you for joining us.

Tim Beard, vice president of drilling, Expand Energy: Thanks for having me.

ND: Tim was among speakers this morning at DUG Appalachia in Pittsburgh. Tim, we talked about a lot of drilling and completions, obviously, on stage. Three areas in particular I wanted to zero in on would be—first, obviously, Expand has been DUC-ing and deferring TILs and curtailing some existing wells via choke. Whereabout is Expand now in that program?

TB: Yeah. So great question. We have about 80 deferred TILs. So a deferred TIL has been drilled. It's been completed. We just haven't turned it in-line. So we have about 80 of those wells. So about a Bcf/d of production is what is sitting there behind the wellhead.

Currently we have about 60 DUCs, plus or minus, and we have been curtailing. And that number fluctuates based on the price. I think we have a couple 100 [MMcf] currently curtailed around the country, so be it Appalachia, which is our Southwest Appalachia asset, our Northeast Appalachia asset or the Haynesville.

Those three areas, we have some amount of gas—and/or liquids in the case of Southwest Appalachia—that we are curtailing currently.

ND: You mentioned the Haynesville. You operate both in the Haynesville and in the Appalachian Basin. A fellow Haynesville operator in the original Haynesville has been doing an extreme stepout in terms of numbers of miles from the original Haynesville/Bossier program north of Houston and making some incredible wells. But these are also super deep, super high pressure, super high temperature. Have y'all been looking at that program to see if there's anything you can apply to yours?

TB: Yeah, absolutely. So we've been looking over the fence and as I said in the other room, I think all operators are remiss if they're not learning from others, looking over the fence, seeing what they're doing, be it from a geologic perspective and/or from an operations perspective. And so we've been paying attention to what they're doing.

I think not only are they seeing tremendous results from a production perspective, but they're starting to lower the price [of D&C]. If you look at the cost of those wells, it's a little bit cost prohibitive currently at plus or minus $3,000 per foot [for] 10,000-foot laterals,. We can all do that math pretty quickly. Those are expensive wells.

But as we were talking earlier, they're just phenomenal from a production perspective. And so as commodity price improves, that area is probably going to continue to get more and more attention. And as midstream companies come in and are able to take that gas out of that area [that's] also a big deal for those folks that are working there.

But how's it affecting us? Well, obviously we're paying attention from a geologic perspective. Do we need to move that direction? But secondarily, it is so extreme from a temperature and pressure perspective that these guys are having to learn how to drill, how to complete, how to produce these wells.

And the good news is, across the industry, people are going to find a way. We've seen that over time.

We talked a little bit this morning about really short laterals, right? When we got to a mile, we thought we were doing great. Now we're out to five miles drilling laterals.

But as I think back to the Haynesville, their temperatures are in excess of 400 F. Pressure is incredibly high. And so the service companies have to come alongside—and they have—and develop tools that can handle these extreme conditions.

And so when they develop those tools, we can then take them to the Louisiana side of the Haynesville where our conditions aren't quite as harsh—still very hot, still very high pressure, but relative to what they're doing in Texas, a little bit different.

And it's going to make us better. And we've already seen some of that, where our efficiencies in the Haynesville are continuing to get better in some of the technology that we're using from a hot-hole perspective is coming from some of the stuff that they're doing in East Texas.

ND: And also in terms of getting better, one of Expand’s two predecessors, Chesapeake, was an early… was second in making a U-turn well. That was actually in the Eagle Ford.... And there are three now in the original Haynesville where you operate, but is Expand interested in U-turns in Appalachia?

TB: Yes. I'll be surprised if we don't do some U-turn wells over the next couple of years. And the "why" behind the U-turn wells, it's not just to be cute and drill a U-turn well. It's because you have some stranded acreage. You have 5,000-foot here, you have 5,000-foot here, you might have a well in the middle.

And so instead of two 5,000-foot laterals, you drill one 10,000-foot lateral and the economics are just much, much better.

You're also getting that 10,000 foot lateral from just one location versus potentially two in some instances.

And so I will be surprised, because we came out here and we drilled 5,000-foot laterals at the genesis or the beginning of the play, if we don't go back and drill some U-turn wells. And I think you'll see that across the country because of that.

Now there's some downhole stresses that are going to play into it. There's some downhole geology that's going to play into it. But where we can, I see that [is] something that we will do.

ND: Super. Thank you Tim.

TB: Yep, absolutely. Thank you.

ND: And thank you for joining us. Find more actionable energy intelligence here at hartenergy.com.

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