Greg Lewis: I had a question about the contracts with Exxon in Guyana, realizing it’s not until the price reset is not until September, but just had a couple of questions around that, and 1 being, it seems like, and maybe it’s always been through the cycles, and it just was not as evident with extra equipment, but it seems like this cycle, everyone’s MPD, and MPD is not included in the dayrate, but it’s an extra, pick a number, $30,000 to $40,000 on some of these term jobs. And really what I’m trying to understand is, in those negotiations, 2 things: 1 is, is it a headline dayrate? And I imagine Noble’s fighting for more and Exxon’s fighting for less, but as these other services, which I assume we’re doing in Guyana as well, are part of the contract, but maybe not in the scope of the dayrate, is that something that’s in play for Noble to get as you renegotiate the next rate?
Robert Eifler: Yes. So, the rate, it’s always hard to decode. It’s hard for us to decode, just like it is for you guys, on when you get total contract value, and there’s a lot of different other services and rates right now, just as you said. We try to deconstruct rates and really understand the various components. Clearly, mobe and demobe have to come out. And then the rest of the other services, we spend time trying to understand what those might be in some of the fixtures that are out there. The rate is supposed to be a global market rate for a tier 1, a 2-BOP, all the bells-and-whistles rig for a 6-month job. And that filters out a variety of different rates out there. And we spend time trying to understand and guess at what the fixtures actually represent. And so, it’s work every 6 months, always takes several meetings, and as we’ve said before, often includes a third party to offer a third opinion, but I think has worked extremely well so far…
Greg Lewis: Oh, yes. No doubt.
Robert Eifler: And we’re at a good rate. Yes.
Greg Lewis: And I think you answered it in saying I wasn’t sure about the duration. It sounds like anything over 6 months. So, there was a 1-year contract in the Gulf of Mexico over $500,000. Not that we should expect the rate to go to $500,000, but a contract like that, even though it was an extension, would most likely be included in the updated price setting.
Robert Eifler: Yes. Without getting into a very specific example like that, I would say that generally excluded are the longer contracts, 2 years and over, and included are globally the rest of the contracts. And for every leading-edge U.S. Gulf of Mexico fixture, there’s generally another fixture out there that’s very relevant, that’s generally a little bit below the U.S. right now. And so, the rate is a basket of all of the relevant fixtures globally, and they all require some adjustments. And it’s not uncomplicated trying to put the basket together, as I mentioned.
Operator: And we will take our next question from David Smith with Pickering Energy Partners.
David Smith: So, I appreciate the commentary in the prepared remarks referencing the open demand for floaters from tenders and pre-tenders that sit at a decade high. I wanted to ask about the demand that doesn’t go through the tender process. If you can give us any color on the interest you’re seeing from direct negotiations, if you’re having more of those, or if really most new opportunities are going through the tender phase.
Robert Eifler: No, I’d say that the direct negotiations, the level of direct negotiations have increased relatively steadily through time. It’s easier to quote open tenders. I think it’s probably a slightly more objective measure. But for sure, a lot of what’s out there and a lot of what we’re predicting will drive demand growth is actually direct negotiation. So, if you remember last quarter, we thought we’d see about plus 10 rigs, perhaps a few more going through next year on total floater demand. And while we see a tremendous number of open tenders, and I think that’s a really positive story, the total demand growth is going to include some healthy direct negotiations as well. Sorry, go ahead, Blake.
Blake Denton: Yes. To provide a little bit just some numerical context of that. When you look at our fixtures over the course of 2023, 54% of those were direct negotiations. And though it’s a small number this year, it’s 75% year to date.
David Smith: Perfect. Appreciate that color. And if I could slip in a follow-up. Just thinking about the little bit of U.S. Gulf deepwater demand for well intervention and P&A, I know those contracts can come with very short lead times. And wanted to ask, in your experience, these forecasts for active hurricane seasons have any notable impact on operator interests to contract for well intervention or P&A work in the July through November periods?
Robert Eifler: It’s a good question. I wouldn’t say that there’s seasonality in the shorter-term demand in the U.S. that we’ve noticed. The intervention market, which I think we’ve said, hinted at before, there is some possible application of the Globetrotters into that market. It is a very short-term in a callout market, it’s a different market than drilling. And I can’t say I’m 100%. It’s a good question, Dave, but I don’t think there’s a lot of seasonality that really drives those dynamics. Look, in the U.S. Gulf, obviously, hurricanes are very impactful, but you get winter storms in the U.S. as well that can be pretty disruptive, to actual rig operations, obviously, less destructive. But anyway, I don’t think there’s a tremendous amount of seasonality.
Operator: And we will take our next question from Doug Becker with Capital One.
Doug Becker: Robert, you mentioned that costs were up from last quarter because of contract prep mobilization, which makes a lot of sense given the contracts we have starting up over the next couple of quarters. Just any high-level comments on the trajectory for operating expense and CapEx over the coming quarters?
Richard Barker: Sure. It’s a very good question. Look, I think from an inflation perspective we’re obviously being impacted by that. I think it’s obviously part of our guidance, if you will. So, we’re seeing inflationary pressure across our entire cost base, somewhere between, call it 4% to 6%. But those numbers are absolutely part of our guidance, both on the OpEx and on the CapEx side as well. Obviously, CapEx was higher in Q1, really down to these key contract startups. And we expect CapEx obviously to moderate in the second half of the year.
Doug Becker: Should we expect it down in 2Q versus 1Q?
