Operator: Our next question comes from Matt Portillo from TPH. Please go ahead with your question.
Matt Portillo: Good morning, all. Maybe just starting out in the Permian, you turned in line an additional four wells in the Texas Delaware. Looking at the state data over the last few years, that’s been an area that’s been quite surprising in terms of well performance. Curious if you could give us any color on the early time performance from these wells, and also just updated thoughts on the spacing design. I know you guys are working on some tests, but may be a bit too early to infer anything, but just curious how you all are thinking about the spacing design going forward.
Pat Wagner: Matt, this is Pat. I’ll take that one. Yes, as you said, we brought on four wells in the first quarter. I would characterize those wells as performing in line with pre-drill expectations. This is a reminder for everyone. I think we heard this a little bit last call. This was a down spacing test, so we did three wells in the Woodford at 880-foot spacing and one Meramec about 650 feet above those kind of between two of the wells. So the key takeaway from early time in this pad is that the wells are — they’re acting just like the other wells, strong oil production, high oil cuts, low oil ratio and already low decline that we’re seeing. The other key takeaway is that there’s been no communication between the Woodford and the Meramec, which gives us a lot of confidence about co-development moving forward.
We do now have 13 wells online across our 55,000 acre blocking position, nine of the Woodford and four of the Meramec. And as I said, we’re very confident now in productivity and we’ve moved it into the Permian asset team and fully integrated it there. In terms of future development, this was a down spacing test. I think our early learnings is that we’re going to probably pursue a 4×4 co-development, which will maximize capital efficiency. But there’s such a large volume of oil in place in the Woodford, we’re going to continue to look at maybe a little bit tighter spacing in the Woodford, and just as we drill the next pad, we will look at that again.
Lee Tillman: Maybe if I could just add too, Matt, we were really a first mover in this kind of combination Woodford-Meramec oil window and we were able to essentially amass a 55,000 net acre continuous position at relatively low cost at 100% working interest. And of course, now we see other operators are starting to get more active in both the Woodford and the Meramec. And I think that all is constructive and supportive of kind of what we’ve been saying all along. And we believe that that this asset can compete for capital allocations. One of the key reasons we’ve now integrated it in with the Permian is we believe we’re out of the exploration phase and really moving into that developmental phase.
Matt Portillo: Perfect. And then, just as a follow-up question, just wanted to clarify on the color for the volume cadence for the year. You guys gave context on Q2 and Q3, which is quite helpful. Just curious as we look towards the second half of the year, I know you’ve got a heavy fill program in the Eagle Ford in Q1 and Q2. And it looks like the Permian. For the most part, will wrap up from a TIL perspective in the first half as well. Any additional color you might be able to provide into Q4 as we should think about volume cadence? I know you gave some color there on Q3, but just trying to figure out how we should be thinking about the back half of the year in general.
Lee Tillman: Maybe let me jump in on that one, Matt. I think as Mike mentioned in his opening comments, we expected first quarter to be right where we landed at, the 186,000. Our guidance for second quarter is right around the midpoint of the full-year guidance. But we do see second and third quarter being an increasing, if you will, oil production trend moving forward, which is really reflective of the capital program. Having said that, our full-year guidance remains intact and — on both the oil and OEB basis. And so that profile will, in fact, generate those midpoints that we provided. And we also are very mindful, of course, of making sure that we maintain momentum as we start thinking ahead to 2024 as well.
Matt Portillo: Thank you.
Operator: Our next question comes from Scott Gruber from Citigroup. Please go ahead with your question.
Scott Gruber: Yes. Good morning. I actually want to come back to the theme of the future opportunities, maybe look out a little bit further. But as we contemplate the growth potential for gas demand along the Gulf Coast, we may need more than just the Haynesville and associated out of the Permian and Eagle Ford. Do you guys have a good sense for the economics in the dry gas window of the Eagle Ford? It’s deeper, so the wells are going to cost more, but wondering whether you have a sense of the breakeven.
Lee Tillman: Yes, well, certainly, as we look at the complete inventory in all of our basins, dry gas today is at a bit of a disadvantage, both pricing and as you say cost, as you get into some of these areas of these plays, the drilling and completion costs will get quite high. We also have, of course, dry gas optionality within our Oklahoma position as well. And that’s a good example. I think, Oklahoma, we put in place a JV structure in Oklahoma that allows us to protect our acreage, keep our crews operating, and in general, be prepared if we do find that we see a more favorable environment for gas production and these combo plays that do rely a bit more heavily on both gas as well as NGLs. But the JV program is a good example of how we’re really keeping everything warm and ready to go.
So I don’t think that gas question is necessarily limited to the Eagle Ford. I think it could apply to Oklahoma as well. And we just need to be ready with opportunities when that makes sense. It’s all going to be done based on return and capital. I mean, I won’t say we’re completely agnostic on commodity. But at the end of the day, it’s going to be driven by economics.
Scott Gruber: Yes, no, of course. It’s good to highlight the Oklahoma position. I’m just thinking about kind of with gas prices depressed here near term, but given the potential demand recovery and future growth, whether it’s worthwhile to contemplate building out a acreage position kind of further south from the inside position, or is that — I know you guys have a lot on your collective plate today. Just wondering whether that’s on the radar or not.
Lee Tillman: Yes. Well, I think you’re right in the sense that there’s, certainly, there is more gas optionality. Even though we’re getting a lot of oil production from Ensign, it also brings significant gas with it as well, particularly in this very strong condensate window. But there are dry gas opportunities within Ensign as well that we could certainly look to exploit in the future. I do think, though, if you just step back, Scott, when you think about our portfolio today, we’re generally kind of a 50% oil, 50% gas and NGL company. And we like that balance and we like that commodity price exposure. So we want to be very mindful of just, again, at an enterprise level, keeping that balanced exposure to the kind of the full commodity price.
And that even includes our E.G. assets, which, of course, have a different kind of commodity price exposure and that they’re exposed to both Brent on the condensate side, and then right now, clearly linked into global LNG. And in the future, that linkage is even getting stronger.
Scott Gruber: Got it. Appreciate the color, Lee. I’ll turn it back. Thank you.
