Tim Duncan: Yes, well, it’s interesting. And that’s another one we’re following on maybe where Leo’s question is, as you think about these volumes. So we own that Tarantula facility at 100%. So you referenced Ram Powell, we own that facility at 100%. We drilled Lime Rock and Venice at 60%. So that other 40% was with a private partner, a private company, a great partner of ours, and they’re going to pay us a handling fee to manage their production, and that ultimately that offsets our operating costs. So we get the benefit of the economics of drilling the well. We get a secondary benefit when we own a facility at a greater working interest than the wells coming to that facility. That means some other party is paying us production handling.
This one, it manifests itself in an override. So there is different structures on how that works, but ultimately they all contribute to lowering your overall lifting costs setup and increasing your net back per BOE margins, which again Sergio talked about on the call. So that’s the benefit of infrastructure. Not only do they aid in your own breakevens and lowering those breakevens, and giving yourself a chance at more inventory than you may not have in the Gulf of Mexico if you didn’t operate this infrastructure. There is a secondary benefit when you’re collecting what we call production handling or PHA revenue or offsetting our operating cost. And so all of that works itself through in Katmai. The bigger that might be, the more of that secondary benefit.
Jeff Robertson: Thank you.
Tim Duncan: Thanks.
Operator: Thank you. And your next question comes from the line of Nate Pendleton from Stifel. Please go ahead.
Nate Pendleton: Good morning. Thanks for taking my questions.
Clay Jeansonne: Good morning, Nate.
Nate Pendleton: My first question regarding future partnership opportunities, that somewhat of what you just alluded to there. And with offshore back in the spotlight a bit, how should we think about the sweet spot working interest for Talos on a given prospect, more from a risk tolerance perspective going forward?
Tim Duncan: Yes, look, that’s a good question. I mean, you know, we do start with what are the things that can help manage corporate decline over the next 12 to 15 months. And so what can we do on the development side, there might be a little higher working interest. It might not really require some of those joint ventures. So what we’re doing in the Lobster field is an example of that. And again referenced in the deck, that’s a really cool project. And so we want to — our first priority is making sure we’re identifying portfolio around those types of opportunities. And then we get to what I would call that middle market, more likely than not two of every three work, and that’s the Venice and Lime Rock types, the Sunspear types.
Those prospects can be 12 million to 20 million barrels. They’re one, well tiebacks. Typically, we don’t want to do those at 100%. We’d like a partner for those. But we may lean in and have a 50%, 60% working interest again, what you saw in Venice and Lime Rock. And then at least once a year, depending on the year, maybe twice a year, we want to kind of put a test out there that could have a really high impact, and Daenerys is an example of that. Those are typically sub-salt. When you look at the landscape of those types of risk-reward opportunities, they have a higher well cost and we should probably have. And they have a, you know, kind of a lower chance of success, but they can be impactful if they work, and they can have a long resource life.
And Katmai, at some point, was that kind of high-impact prospect. It’s now a high-impact discovery, but we’re probably going to have a little less working interest, maybe 25% to 30%, which is where we are at Daenerys at 30%. So it’s just a little bit of an education on how we think about that. We want to make sure we’ve got the right reinvestment rate. We want to make sure we have the right shots on goal. One thing I’ve talked about in previous calls is we could have a very busy year, both in the drilling and hookup side, one year and then a lighter year the next year. So you kind of have to think about our portfolio and two-year cycles, depending on kind of what the success is on the wells we drill. But that gives you an example of the risk-reward mix.
Nate Pendleton: That’s great detail. I appreciate it. And for my follow-up, referencing Slide 9 that you touched on in your prepared remarks, it looks like most of the blocks you acquired are in areas that have existing seismic or adjacent to current acreage. With the exception of the blocks at the bottom in Walker Ridge, is there anything you can share about those blocks or blocks in general where you’re kind of stepping out of either seismic coverage area or the existing footprint?
Tim Duncan: Yes. So there is a deep play that we think is evolving down in that area. And we’ve got — there is some ancillary seismic in there that we have that probably should have shown up on this map. And so that’s a longer hold. So a lot of what we do, there is some things that we can identify and say, hey, look, I know exactly what that does. It’s geophysically driven, meaning we think it’s got a hydrocarbon indicator or an amplitude, depending on, Nate, who you talk to. And that’s one that you’re going to start permitting and defining and get on your drill calendar in the next three years. And then there is other things you’re doing where you say, hey, look, there is a big geological play here. We can see why the Majors are looking at it.
If this takes off, we want to have an acreage position, and these are longer holds. They’re 10-year leases. And so you’re trying to grab it while you can, knowing that it may be something that bears fruit down the road. And so there is always a little bit of that every time we go to a lease sale. And I think that’s an example of that. So, deeper play, I actually do think we have a little data down there that might be a misprint on our side. But I can just tell you just by saying the words, Walker Ridge, it’s going to be a little deeper play, a little longer hold. But, I mean, this is a basin where the minute you focus too much on one of those risk-reward strategies, if you focus too much on development or focus too much on that middle market prospect and don’t think about some of these deep evolving plays, you’ve missed the benefit of what the basin has to offer.
So we’re always thinking about all of those categories when we go to the lease sale.
Nate Pendleton: All right. Thanks for taking my questions.
Tim Duncan: All right, Nate. Thanks.
Operator: Thank you. And your next question comes from the line of Jarrod Giroue from Stephens. Please go ahead.
Jarrod Giroue: Hi, good morning, guys.
Tim Duncan: Good morning.
Jarrod Giroue: Hi, I was just curious about the Daenerys prospect. Tim, in your prepared remarks you said that you guys could get to it late this year or could push into early next year. I guess, what’s the determining factor for a 4Q or an early 2025 spud? And with that post-spud about how long until you expect first oil? Thanks.
Tim Duncan: So I think that is really dependent on rig deliveries as much as anything else. And so we will get the rig kind of right where we want to get it relative to Katmai and then the execution of Katmai and then we go straight to Daenerys. And we have flipped the order. Earlier in the year, we were thinking Helm’s Deep, but I do think Daenerys is high-impact enough. We have a partnership that’s excited about it. We’ll probably move that to the head of the line, so rig delivery will be a part of that. The rig that we’re utilizing there is on one of the prospects we announced that had some recent success in [clapboard], they’ve got to wrap that project up, and then we have a chance to get that rig, hopefully on time. So very well could be on time.
But again, rig delivery, rig dependent. Getting that hooked up would take a little longer. That is a deep test that has a tremendous amount of potential. What we’re designing in there is to try to get two penetrations into the structure and almost to talk about the Katmai. If we can get two penetrations into the geological structure in this first test, we’ll learn more and it’ll help us design what the, you know, what the outlook is. There are some host facilities in the area, it could be big enough that people could think about new construction, but let’s see what the results are. Our focus is always on tiebacks, but that one’s going to take a little longer. That’s more of a two- to three-year cycle time than opposed to kind of the 18-month type of cycle time that you see with things that are a little closer to infrastructure where you feel like you know exactly what you have.
So this is a — this is the type of project that has more engineering study, more long leads, more of an — kind of get to an FID, as some of the things that we do in our typical portfolio. So a little longer cycle time. I think the big catalyst on next year, if we think about production next year, is the Sunspear discovery that we had last year, that we’re trying to get online in the first half of the year. And then again, if Katmai is successful, as we anticipate and hope it will be, that we get online in the first half of the year, next year as well.
Jarrod Giroue: That’s perfect. Thank you for the color. And then one more. My second question relates to the transactions during the first quarter. Do you expect any more transaction-related costs in the second quarter?
Sergio Maiworm: We might have some severance costs and some other minor transaction costs in the second quarter, Jarrod. But the bulk of it should have been already recognized in the first quarter. So we might see a few things in the second quarter, but not a lot.
Jarrod Giroue: Yes. I think, perfect…
Tim Duncan: I think that I thought you were asking we should anticipate more transactions, and if we do more than four a quarter, I think, Sergio, I reach across this desk and hit me. So, yes, there could be some lingering one-time cost.
Sergio Maiworm: Yes.
Jarrod Giroue: Perfect. It’s cool. Thanks for the answers.
Tim Duncan: You got it.
Operator: Thank you. And your next question comes from the line of Paul Diamond from Citi. Please go ahead.
Paul Diamond: Thank you. Good morning, all. Thanks for taking my call. Just wanted to quickly touch on those 17 blocks that we talked a little bit about splitting them between kind of shorter cycle in that three-year kind of time horizon, those longer cycle. How should we think about the breakdown of those? Is it 50:50 or is it 70:30, just how does that — how is the breakeven…
Tim Duncan: Yes, that’s a good question, Paul. And it’s important that we keep asking those and kind of keep that education. I think, I talked about those three buckets kind of that development, again what I would call that middle market, one well tie-back, and then the broader multiple wells, bigger projects. The development stuff typically is pretty quick. I would say, six to 12 months. There’s infrastructure in place. We’re right around our own facility, maybe within two miles of our facility, or maybe we’re actually drilling it from our facility. Those turnaround quickly, those middle markets, Venice, Lime Rock, Sunspear. I would say those are, you know, kind of 18-month turnarounds. You know, if it takes a little longer for new equipment, maybe as much as two years, but more of that 15 to 18-month turnarounds.
