Doug Leggate: Okay. My follow-up is, John, there are a few teasers in the deck about the status of Suriname moving towards potential hub development, I think it was the expression — and you said you’ve got the results of at least the first appraisal well at Krabdagu. I wonder if I could ask a question like this. You said the result is in line with expectations. So what were the expectations? And what would you need to move forward by way of resource upside to the more than 800 that you identified in the deck today?
John Christmann: I would just say, Doug, we’re still getting results from Krabdagu. We’re in the buildup phase. To put things in perspective, I won’t — I’m not going to give you a predrill expectations, but the well was in line. But I will remind you that the Krabdagu 2 is 4.9 kilometers from the discovery well. So — and Krabdagu 3 is 10.3 kilometers from the discovery well. So when you look at that map, sometimes you forget just how large of an area that is. And obviously, we’re very pleased with the early data and the results we have from the appraisal well. But you know our history has been able to come back with connected volumes, and we’re not ready to do that yet because we’re still collecting pressure data.
Operator: Our next question comes from Bob Brackett at Bernstein Research.
Robert Brackett: I’ll stick on the Egypt topic. One is just to refresh my memory that in Egypt, natural gas flows domestically sort of toward the Cairo Basin area, whereas oil tends to flow north and you export it and capture those revenues. Am I remembering that correctly? .
John Christmann: Yes.
Robert Brackett: Okay. The follow-up would be, you mentioned that to expect Egypt to be flattish 2Q versus 1Q. You mentioned production disruptions, some of which are temporary. Am I being too much of a lawyer to suggest that some of those are not temporary? And could you maybe give some color in terms of the cadence of getting oilier through the year? You’ve guided 60% oil for Q1 rising towards 64% for a full year average?
John Christmann: Yes. Bob, I’d say the first thing is, you know we’ve got a very large asset base area that stretches really from Cairo, almost to be. And we’ve got a number of fields, and I’ll let Dave walk through some of the temporary things and then another minor issue.
David Pursell: Yes. So counselor, when we think about this, — the capital program is performing as expected. So new wells and recompletes, those are on track. We’ve had slightly lower base production. So a series of things, and we’ll highlight a couple of the big ones. We have an unplanned downtime at a gas plant, which will impact condensate production. We’ve had some ESP failures on some of our larger oil producers. Those are the temporary issues — we’ve done some injection conversions taking producers to waterflood injection and that takes some time to see the oil production benefit from those. And then one of our mature fields, our field experienced an increase in water cut late first quarter. And put that in perspective, it’s a 3,000 barrel a day field that’s now producing close to 1,000 barrels a day.
So it’s not a big producer, but on the margin, that loss of 2,000 barrels a day impacted second quarter. It actually had a slight impact on the first quarter as well. So when we look at the second quarter, we just felt like given those events, it was probably appropriate to guide conservatively flat I’ll tell you, the team is expecting to beat that. So we’ll see, but we want to guide conservatively and we’ll see as we go through the quarter some of the temporary issues will get back. I think it’s important to highlight given the pace of new well drills, the quality of those wells, the recompletes, we remain confident in our ability to grow production in the back half of the year. So no change to guidance for ’23.
Operator: Our next question comes from Charles Meade at Johnson Rice.
Charles Meade: John, I wondered if we could talk a little bit about the time line for these — the Krabdagu appraisal wells. And maybe I was — maybe I was off on the wrong track, but I thought we were going to get the — some of these appraisal results a little earlier. But I found myself wondering maybe these wells, you’ve designed them to be eventual producers, and so they took longer to drill. So could you comment on, I guess, both of those things, what the time line is and whether the current time line is — fits with what you expected and whether these are going to be producers and when you think you’ll be in a position to share that connected volume investment.
John Christmann: Yes, Charles, I don’t know where you got any ideas on time line because it wouldn’t have been from us, but just because Total is operating. I would say the Krabdagu 2 moved on pretty much as expected. We’re just in a period now where we’re gaining data through the buildup. And so that is the most important information in terms of connected volumes. I will say the Krabdagu 3 well is running a little behind, but that also was a brand-new rig that was brought in the basin. And so there’s been some fits and starts on the drilling of the third well. So I wouldn’t read too much into that other than it just is taking a little longer than anticipated.
Charles Meade: Okay. And then going back to U.S. onshore in natural gas specifically, I want to commend to you guys before turning the dial back on that. It’s — I know it may be — sometimes seems easier to do from seats like mine than the actual reality ever for you guys. But if we — to your comments about being bullish on the longer-term outlook for natural gas, what — can you give us a sense of what kind of price or what — or how long at a certain price you would need to see natural gas before you would want to turn the dial back up on U.S. lean gas activity?
John Christmann: As we said in the prepared remarks, we’re seeing good results on the program there. There’s no reason to invest the capital today into this price environment. And so I think we want to see the infrastructure kind of get resolving it through this and feel like we’re in a good place because we’re making long-term investment decisions here. I’m very pleased with the results but we want a clear pathway on a more constructive price environment for gas.
Stephen Riney: Yes. And — if I can just remind people also, John, we sell all of our gas produced in the Permian Basin in the Permian Basin. And so we’re getting Waha or El Paso Permian prices for that gas. And we have our transport obligations to the Gulf Coast, but we buy gas and sell that on the Gulf Coast. We make that margin regardless of whether we produce a molecule of gas in the Permian or not. So everything has to be evaluated on the basis of we’re selling this at Waha, not at the Gulf Coast.
Charles Meade: Right. But no — nothing you’re prepared to share about what Waha needs to be for some duration before you decide to put dollars back there?
Stephen Riney: Well, I think the simple thing would be to say that Waha has to be attractive enough to compete with more oil drilling right next door.
Operator: Our next question comes from Paul Cheng at Scotiabank.
