Mark Mey: So a couple of things there. Scott, one, that $90 million includes some contract prep of about $10 million. So the rest is about $80 million. It was actually a little bit lighter than you would think it is. We have seen some inflation, no question about that. But as you know, we do have what we refer to as care agreements with most of our OEMs. And part of the care agreement is a cap on the inflation each year and that cap range is around 2%. So even if inflation is 4% or 5% which it clearly is at the moment, we’re not experiencing all of that with a lot of our spend. So next year is also a lighter year when it comes to SPSs for rigs that are older. So you’re not going to see a lot of money being spent on that. And we’ve also maintained our rigs fairly well throughout the down cycle.
So we’re not going to have a catch-up in ’23, ’24, ’25 and beyond. So I think this is what you can expect from us going forward. Our CapEx has been very high because of newbuilds. But on a sustaining basis, we’ve been saying this for a long time and don’t expect to see very big numbers from us going forward.
Scott Gruber: And just a quick follow-up on the SPS side. You will have a few more, it looks like in ’25 and ’26. And I know you’re not spending as much on the 10-year SPS this cycle as you did last cycle but just kind of ballpark what would a 10-year SPS run you now?
Jeremy Thigpen: It all depends on the asset because with these agreements — we have 10-year contracts with these OEMs. So part of the benefit to Transocean with regard to these agreements is that the rig equipment stays certified 24/7, 365. So the cost benefit — because we pay a day rate to our vendors, the cost benefit is that we can do — for the drillships we can do the SPSs while the rig is working in-service for the 5-year and 10-year. Obviously, we’re just past halfway with these contracts. We’ll start to look at renegotiating this or terminating this or whatever we decide to do with regard to those agreements for the years 11 through 15 or beyond. But clearly, for us, the 5 and 10-year is not a big number and most importantly, for the drillships and other out-of-service clients.
For the semis [ph], however, we do have to take those rigs into the dry rock because we have to inspect the hull, the pontoons and under carriers of the rigs and that can be 15 to 20 days.
Operator: And our next question comes from Fredrik Stene with Clarkson Securities.
Fredrik Stene: I wanted to circle a bit back to the market here and weighing short to medium term versus long-term outlook. And I think we’re pretty much aligned in what we think about this market that it’s going to be a highly sustained long upcycle. But based upon how estimates for drillers in general has been revised a bit downwards now for ’24 and partially ’25 over the last few months, there seems to be some concerns that at least ’24 will be, call it a bit volatile. And then you partially touched upon it with white space and all that. But I just wanted to confirm that what’s happening behind the scenes or underlying? And then, maybe particularly in relation to your comments about longer-term work taking longer to finalize.
Is the white space that we’re — you might see on a few rigs in ’24 for you and peers more like a result of, call it, what can we say, arbitrary contracts and start-ups are not really a result of anything changing in how you look at this market in the long run. It’s just people need time to decide and the consequence of that is a bit of white space, although it shouldn’t be taken at a time of a weaker market. Sorry, for all those words but hopefully [ph].
Jeremy Thigpen: No, that makes sense. Yes. So really, that’s exactly our view is that — for example, we talked about a couple of rigs. So if we take the [indiscernible] actually was a winner in one of the tenders that just did not get consummated. So she would have — assuming that had gone ahead, there was some technical issues on wells that they decided not to do. But assuming that got a hedge, she would be booked now and then we’d be busy getting ready for that contract. So, I really don’t think the fact that you have a couple of spots of white space are indicative of the market. I think it’s more indicative of just confluence of events. So for example, in the U.S. we really had no hurricanes this year offsetting any activity which is great, right?
But normally, that does have an impact on the length of term for some of these rigs. And likewise, in some of the other places we had instances where options were perhaps not taken on rigs, in one case, actually, because the results were so good that we decided not to drill the extra wells. So that’s kind of like a victim of your own success. But other instances where either some political stuff happens or there’s some delay on trees or something like that — and options weren’t taken. So I think like, if we think back to where we were last year, we had tons of white space and a lot of it got filled because we “got lucky” in terms of programs running longer. This year things have not run longer. They’ve really gone either 2 plan or we’ve delivered ahead of time.
So on a macro view, that’s actually a really positive thing because it means that the well cost for the operators are coming down again. And we think that’s positive for building larger demand as we go forward. It’s just slightly unfortunate because some of those rigs were on the short-term contracts that we talked about. But the really good upside with a substantial portion of our fleet migrating to the long-term contracts, those things are not going to be an issue anymore as we step into — later in ’24 and ’25.
Fredrik Stene: And just a follow-up on that. Now that we’re seeing some of this white space in ’24 for these various reasons, do you think, all else equal, that this has delayed the pace at which capacity will be reactivated, either from cold stacks or from yard, both kind of for the market as a whole but also on your own now? I think you’re controlling most of that cold stack.
Jeremy Thigpen: Yes. So like a good example might be what’s happened in Brazil. So obviously, I can’t really talk about fixtures that have yet to be made but there’s rumours that there was a switch by a winner of a particular project that they decided to put forward assets that are already on the market rather than bringing out 2 assets from the shipyard. So that would be a consequence of — well, it makes sense to place your active fleet ahead of reactivating or standing up newbuild rigs. So that’s probably the best example to date that there is still plenty of discipline there amongst the drillers that they’re not bringing out rigs at all costs. They’re basically saying hang on a minute, this makes sense for us to keep that capacity off the market and to place our active rigs.
