Jacob Roberts: Yes, that’s perfect. I appreciate it. And just a second question. Can you remind us on the current expected time line of the Martica payments when those thresholds will be hit? And what that ultimately looks like once they are threshold is met?
Michael Kennedy: Yes. As you rightly recall, they’ve actually — they no longer participate in our wells that ended March 31, 2023, but there is kind of that runoff of the PDP base. That does revert back to us when they hit certain rates of return. And right now, we’re forecasting that to be starting in ’26.
Operator: Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.
Kevin MacCurdy: We appreciate all the details you gave on the NGL marketing in the prepared remarks, but my question is, as it relates to your realized prices, it looks like your C3+ prices were much better than the weekly average benchmark pricing. And just curious if there were some onetime items that benefited you in the first quarter versus the benchmark? Or do you expect that premium to continue?
Michael Kennedy: Yes, there aren’t any onetime items. We’ve really switched this year to more international exposure, better contracts, not linked to Mont Belvieu. So we’re still kind of working through those relationships Obviously, the international pricing has been better than domestic pricing. And as that continues, we see a higher NGL realizations. You saw that in our increased guidance, increased it by $1. So as we continue to kind of watch the actuals versus kind of our forecast, we’ll get a little more dialed in on that. But it’s really just due to us switching to internationally linked liquids contracts versus domestically linked in prior years.
Kevin MacCurdy: Great. And as a follow-up, we’ve heard from other gas companies that are changing their activity plans given kind of the weak spot prices, what would make you consider pushing out wells until later in the year? Or are you overall happy with the equivalent price you received?
Michael Kennedy: Yes, it’s really dominated by liquids pricing. I mentioned on prior calls, we do have one pad. I mean we’re only running 2 rigs and 1 completion through. We do have 1 pad in the capital program that’s a spot we have had for the third quarter of this year, and that’s one that’s still to be determined. If it was based on current month prices today, that was one that would potentially be deferred and then that would put you at the low end of the capital guidance range. The other pad is just one completion line. So running that with our 2 rigs is very efficient, and it’s very much 1,275 to 1,300 Btu gas, so very high in the liquids content. So that’s what drives the economics. I think in the first quarter of our revenue, 55% was liquids and only 45% was gas. So you can see how much the liquids prices really influences the economics of these wells.
Operator: Our next question comes from the line of Betty Jiang with Barclays.
Betty Jiang: Can you provide a bit more detail on the startup of the Plaquemines LNG? Do we need to see the first cargo loading or same chemical start-up before seeing any material feed gas demand. You mentioned that the TGP line, the 500 line has capacity of 900 M. Just any view on how quickly we could see those feed gas demand reach those levels?
Justin Fowler: Betty, it’s Justin. Yes, so when we look at the data that we have so far on Plaquemine, you’re correct, the Tennessee project, the Evangeline Pass project should start up July 1. Capacity of 900, the marketing analysts will be tracking the vessels that will be parked waiting to load. So that will be a data point to watch. The vessels that are showing up to the facility as we approach July, and then we’ll see through the nominations into that new Evangeline Pass project. So in theory, once we get to July, the physical gas is flowing, we’ll start getting a better gauge of how quickly the liquefaction trains are ramping to at least mechanical completion.
Betty Jiang: Got it. No, that’s helpful. And just following up on pricing. Clearly, your guys’ view is that the current future strip prices is not reflecting the dynamic around that hub. Why do you think that’s case? And what will be the catalyst to drive that relative hub pricing higher?
Justin Fowler: So you’re referring to the Henry Hub pricing?
Betty Jiang: The TGP 500 line pricing relative to Henry Hub.
Justin Fowler: Yes, Betty, we are seeing the price reaction at 500 in the forward markets that’s just looking at financial basis alone. So looking at financial basis alone, in the summers on Cal ’25 and Cal ’26 are already showing plus $0.40. That is, again, just financial. So those points will command a physical premium, which we’ll start to develop as we get closer to delivery but there will be a physical premium component as well. So if it were $0.10 to $0.20, let’s say, you’re now at $0.60 or $0.70 over Henry Hub as that physical gas starts to price closer to delivery.
Betty Jiang: Got it. And is there a physical gas — physical premium today for the gas?
Justin Fowler: Today — it varies, Betty. We’ve seen different premiums. Last summer, we were seeing very high premiums in the summer months on the physical side, and that’s because there still is power generation requirements in the Southeast when the temperatures get hot and AC load starts to increase. So yes, we have seen those premiums in the past, but it can trade flat to plus.
Betty Jiang: Got it. That’s helpful. If I could turn to question just on the certified gas side, it’s good to see that you guys increased the certified gas coverage under Project Canary. Do you expect all of your production to get certified at some point? And also kudos to you guys on the emission intensity on the production that’s really low relative to your peers. Is there much more room you can do to reduce emissions organically from here?
