Mark Mey: That’s correct, yes.
Operator: And we have our next question from Kurt Hallead with Benchmark.
Kurt Hallead: I always appreciate the color. So in the — just in the context of terms and conditions and it looks like you have — you referenced a number of opportunities where you’re going to see a 3 to 5-year kind of contract terms. Again, that kind of historically wouldn’t necessarily jive with a landmark new high day rate, right? Usually, you’re trading some term for rate. So just kind of curious as to those dynamics and kind of how you’re thinking about them? And again, in the context of you as a management team trying to maximize returns and maximize cash flow as we go into this next up cycle?
Jeremy Thigpen: Yes. I would say we covered it a bit in the prepared remarks and I think a bit last quarter, too, Kurt but I mean the — we sit as a team and really evaluate each rig and each opportunity. And there are times with certain rigs where you say, you know what, we don’t want to fix this rig to a longer-term contract that we believe is going to be a discount to market by the end of that contract. And there are other rigs, we want to keep that rig and kind of test the market on short-term or continue to push day rates as much as we possibly can. Now the risk in that is you get some idle time every now and then, you get some white space, as we do right now with the Invictus. But that is the rig that we have continually used to push rates and got us to where we are today.
So with some of our rigs, we will continue to take that strategy. With other rigs, we’d like to lock them up into 3 or 5-year contracts at what might be a discount towards the tail end of that contract because it gives us that firm backlog and that visibility to future cash flows. So it’s really this portfolio management approach that we’ve talked about on previous calls and we continue to do that with each opportunity.
Mark Mey: Yes. I think I’d just add, we also are very specific about what we target in terms of the specification of the rig matching up with the requirements of the tender or the program. So I’m kind of a little bit counter to previous cycles where all the best rigs got fixed first at the lowest day rate. We’ve been quite purposeful in trying to keep a couple of them available so that later in the cycle the operators can still get their hands on high-specification top spec rigs. And of course, that might come with a little extra cash.
Kurt Hallead: So I guess my follow-up question here is, you kind of referenced or you addressed some of the questions earlier on about — a little bit of a lull in new contract announcements as we kind of progress through the second half of the year. But is there also an element of — are you seeing an element where the oil companies are kind of looking at the same rig availability profile that everybody else kind of sees and basically now at a point where they are making decisions to push off project start times beyond 2024 because they just can’t get the rigs that they want?
Mark Mey: I think there’s probably an element of that, that if you — for example, if you’re going to do a P&A program, then obviously, you would prefer to be able to push that to a point that you think day rates will be lower or you find the right rig or the specification rig that can do the work and you can get it at a reasonable rate. I think, if you look at what’s going on with the majors — and I realize that not all of the information is public but if you look at what’s going on with the majors, you’re going to see several fixtures made in the next short while that are for multiple years and they’re on higher-spec rigs. So these guys are in the market today, kind of working diligently towards placing the right assets where they need them.
So I kind of think it’s a little counterintuitive that you see that there’s a lot more direct negotiation stuff going on today that you don’t necessarily see in the tender market as such. And I just think you’re going to continue to see — I wouldn’t even say it was a debt; it’s just good in terms of long-term contracts. You’re going to continue to see steady fixtures being made for multiple years. And if you think about where we were like just 1 year ago, we were looking at an activity chart that literally had a couple of handfuls of rigs that had the longer-term stuff on it. Now we’re talking about somewhere in the region of, kind of, 15 to 17 of our rigs have got more than 2 years’ outlook on them. And of course, by the end of the year or in Q1 next year, we expect that to get up to 20 or so.
So I mean, I just think this is the transition period because you just have fewer short-term opportunities but longer and larger number of long-term opportunities. So this is just the — kind of the natural ebb and flow that Jeremy was talking about.
Operator: And our next question comes from David Smith with Pickering Energy Partners.
David Smith: So this is actually a question about cost. So please bear with me a second. But the average reported ultra-deepwater rate in Q3, $406,500 [ph] a day. I know that doesn’t include reimbursables or contract termination. But multiplying that rate times the in-service days reported suggests about a $44 million difference versus the reported ultra-deepwater revenue of $516 million. The delta for the ultra-deepwater fleet have been averaging around $20 million the last several quarters. I just want to verify if Q3 was just a big step up in the reimbursable revenues with a likely similar amount of cost?
Jeremy Thigpen: Yes, David, let’s take this mass offline [ph]. I don’t want to go through this when we try to talk about the macro…
David Smith: Sorry. You bet.
Jeremy Thigpen: We can reconcile this for you offline.
David Smith: Then a quick follow-up, if I may, the support cost, $67 million, was that a little step-up versus the prior run rate? Was there anything anomalous? Or is this a good run rate to use?
Jeremy Thigpen: Well, we do have higher reimbursables, no question about that and we’ve seen more and more customers requesting that we buy things, perform services on their behalf. It’s so much easier for them. So as an example, if you look at the Petrobras contracts signed 2 or 3 years ago, very low in reimbursables. And you look at the ones, now much, much higher. So yes, there is a higher run rate of reimbursables. But like I said, we can give this to you offline and give you the math.
Operator: And our last question comes from Scott Gruber with Citigroup.
Scott Gruber: I had a question on CapEx for next year. Mark, the base maintenance spend for next year at around $90 million sounds rather benign. Are you just not seeing much inflation in service costs? Or is this really a reflection of the initiatives around how you guys manage maintenance spend that’s keeping the lid on spending?
