Scott Hanold: I appreciate all that context. And, before I ask my next question, I want to extend my congrats to Billy as well. Obviously, we all appreciated your insights and expertise over the years. And so, my follow-up question is could you all refresh us on Trinidad a little bit? I mean you obviously have some growth coming there that was planned, but remind us the economics and how pricing is set in that region relative to say like what we’re seeing with Henry Hub pricing?
Jeffrey R. Leitzell: Hey Scott, this is Jeff. Yes, just on the activity in Trinidad, we’re currently just running our one rig program there and everything is going really smooth. Earlier this year, we completed two of our remaining wells there in the modified U(a) Block, successfully and brought those online. And, we’re currently drilling and completing a couple of exploratory wells in the SECC Block. And then after that, we’ll move the rig and we’ve got a couple of recompletes to do in our Sercan area and then one more exploration well to finish up the year in TSP area. Another note that I’ll point to, too, is we’re also installing our Mento platform. Everything has been on time and looking good there, getting the facilities in place and that’s in our SMR Block. And, what that will do is that will really set us up for the program next year. So, and as far as the marketing side, I’ll hand it over to, Lance to give a little color.
Lance Terveen: Yes, Scott. We’ve always been real pleased there in Trinidad, especially when we think about our price realizations and obviously meeting that local demand into the country. So, I think you can see even with the price realizations that we had in the first quarter, they were very attractive. So, we continue to see that kind of on a go-forward basis.
Operator: Thank you. Our next question comes from Leo Mariani with ROTH MKM.
Leo Mariani: Yes. Hi. I wanted to just follow-up a little bit more on the exploration side. Obviously, you guys seem happy where you are in the Utica, but just wanted to kind of ask in terms of activity levels, is there other kind of ongoing exploration still this year and some of these U.S. oil stealth plays and perhaps you can just talk about kind of levels or wells and you’re not going to reveal necessarily any of the specific areas. And then, just on a related point, obviously, you guys have talked about this exploration being able to kind of drive down the DD&A rates for the company, happen to notice that your DD&A rate did go up a fair bit here in the first quarter versus where it was in fourth quarter. So, maybe you could just kind of wrap it all together and give us some color on that?
Ezra Y. Yacob: Yes, Leo, this is Ezra. I’ll start with the exploration and then hand the DD&A details over to Ann for an answer. On the exploration side, yes, we do have some exploration dollars in the budget this year as we highlighted on the first quarter call. We continue to explore for, yes, we continue to focus on oil plays, but at the core of it what we continue to explore for things that are going to be additive to the quality of the corporate portfolio. And, that’s what you’re seeing with the Utica obviously. So, that’s a major success for us. We’re not exploring for things that are simply just going to add inventory. We really want them to be additive on returns basis, additive on a cost of reserves or a funding and development cost basis and that’s how it contributes into lowering the DD&A rate.
This year, we are drilling a couple of what I would call initial wells or I hate to call them wildcat wells because these aren’t frontier types activities. These are in basins where there’s data and there’s been historic production and things like that. But, let’s call them the initial wells to test some exploration ideas. And then, we’ve still got another stealth player too that are a bit more in say a delineation phase where we’ve drilled the initial well, we’ve been encouraged with the initial well results and we’re continuing to test and see if it’s going to clear those hurdle rates that I talked about. The big thing I’d say is these days our exploration plays in these initial wells, and I think I’ve highlighted this before, in the U.S. the way we operate through exploration, there’s so much data that we’re not really drilling these initial wells and to see if they’ll actually produce oil and natural gas.
It’s not like we’re testing whether or not the rock is productive and could we end up with a dry hole. These days, it’s really about when we get the oil and gas to surface, is it what we expected, is it going to be economic in such a way that it really competes with the existing portfolio? Are we exploring? Have we found something that really commands investment and taking rigs off of another play? And I’ll hand it over to Anne.
Ann Janssen: The DD&A you saw increase in the first quarter was just due to a one-time prior period adjustment due to some natural gas production being used in our gathering systems. We did come in at guidance level and you can’t expect that DD&A to moderate over the remaining three quarters for the year, we’re expecting about $10.50 for the remainder of the year.
Leo Mariani: Okay. I appreciate that color. And then, just wanted to follow-up real quick. Obviously, you guys are pretty optimistic on natural gas kind of laid out some pretty big demand increases over the balance of the decade. You spoke a little about 2024 second half continuing to look better. Maybe if I just wanted to focus a little bit more near-term, as you look at ‘25 strips kind of just north of [350] (ph) or so, Are you just increasingly bullish on ‘25, do you think that strip price is pretty reasonable or do you think things can potentially be better than that? I think everyone’s kind of on-board that demand will be a lot better later this decade, but just want to maybe focus a little bit more on kind of the next year or so?
Ezra Y. Yacob: Yes, Leo, this is Ezra. I don’t know if I’d call it bullish on ‘25, but I would say that we’re constructive. As I said, we’ve seen a surprising upside on the amount of natural gas demand for power generation over the last couple of summers and we continue to think that’s going to be true this summer. A big part of that is coupled with coal retirements. We also think the pull on natural gas this summer because pricing is soft will also continue to be great as well. You combine that with the reduction in rig activities over the past eight months or so, and the fact that operators now are also starting to curtail volumes. We think that’s going to bring down the supply side to a point where you could actually make some pretty good progress on those inventory levels in the back half of this year.
That with a little bit of feed gas starting to be taken on the LNG, so that’s it gives us a little bit of confidence headed into 2025. But you are right, there is quite a bit of an overhang right now that we need to see come off starting with this summer.
Operator: Thank you. The next question is from Paul Cheng with Scotiabank.
Paul Cheng: Thank you. Good morning. I have to apologize. I want to go back into Utica. If I’m looking at from a well cost or that well productivity, what kind of improvement do you need in order for you to move from the appraisal mode into the, or the elimination mode into the manufacturing or production, development mode? And also that, based on what you can see from your inventory backlog, what is once that you can feel comfortable about the delineation, what is the development program look like, whether it’s in the number of rig and crew or number of wells that you expect going to come from that on a per year basis? That’s the first question.
Keith Trasko: Yes, Paul, this is Keith. So, I’ll start on the well costs. It’s still early on in the play. The team continues to drive down the costs. We see a lot of room for further efficiencies. The consistent activity this year with one full rig has helped that a lot. We like that generally in the area, it’s an easier operating environment compared to a lot of our other plays. That’s consistent geology. It’s a little bit shallower depths. Example of that is a 3.7 mile lateral we just drilled on the Sables, we also brought in a refrac crew for higher pump rates and increased, efficiencies. And overall, we see development costs someday getting to be a little bit lower than the Permian even on $1 per foot. But, the great thing is that this play just has the opportunity to benefit from the learnings of all of our other plays and EOG best practices.
On the well performance side, we’re really happy with the wells, as I and Ezra, kind of already touched on. We’d see that these compete with the best plays in America, very comparable to the Permian on a production per foot basis, both in oil and equivalents, really highlighting our differentiated organic exploration strategy. The development program as far as rigs and crews and number of wells, it goes back to growing at that pace where we can still learn and just the market based portfolio. We don’t necessarily have to ramp this up aggressively.
Paul Cheng: I see. Yes, before I ask my second question, I also want to add my congratulations and best wishes to Billy. Thank you for the help over the past several years. The second question I think is for Ann. This year that you have about $400 million on strategic infrastructure spending, I assume that it’s not every year you will have that, but throughout the cycle, you’re always going to have some strategic infrastructure spending, I suppose. So, what will be a reasonable average upon the cycle assumption, for the strategic infrastructure spending, and also that, add to overall spending level for the infrastructure or non-D&C for you guys?
Ezra Y. Yacob: Yes, Paul. This is Ezra. Yes, the $400 million of infrastructure, the strategic infrastructure that we’ve highlighted before, which we couldn’t be more excited about because of some of the long-term margin expansion benefits that Jeff highlighted in the opening remarks. These are projects that, historically we look for opportunities like this, but they’re very rare to present themselves where we can take on infrastructure projects that generate such a compelling rate of return. We’ve talked about the Verde pipeline is expected to generate about a 20% rate of return uplift. And, then on top of that, we get that GP&T savings and net back uplift of $0.50 to $0.60 per Mcf over the life of the asset. Similarly, on Janus, the gas processing plant in the Permian Basin, that one also has roughly an anticipated 20% rate of return.
And then on that one, we have a GP&T savings and net back uplift of about $0.50 in Mcf. If we could continue to find some of these projects with that strong of a return profile and that much value creation for the shareholders over the life of the assets, we would be interested in continuing to do them. But to be perfectly honest with you, typically those margins get squeezed down to a point where we don’t want to do them. It’s really more beneficial for a third-party to come in and do them. But, there are times in the cycle where and it seems to happen every five, eight, 10 years or so where there ends up being enough margin there where we see the opportunity to go ahead and capture that value for our shareholders.
Operator: Thank you. Our next question comes from Derrick Whitfield with Stifel.
