Thank you for standing by. My name is Rebecca, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Corporation Second Quarter 2025 Earnings Call. [Operator Instructions] I would now like to turn the call over to Ian MacPherson, Vice President of Investor Relations. Please go ahead.

Thank you, operator, and welcome, everyone, to Noble Corporation's Second Quarter 2025 Earnings Conference Call. You can find a copy of our earnings report, along with the supporting statements and schedules on our website at noblecorp.com. We will reference an earnings presentation that's posted on the Investor Relations page of our website as well. Today's call will feature prepared remarks from our President and CEO, Robert Eifler; as well as our CFO, Richard Barker. We will also have with us Blake Denton, Senior Vice President of Marketing and Contracts; and Joey Kawaja, Senior Vice President of Operations. During the course of this call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management and are therefore subject to certain risks and uncertainties. Many factors could cause actual results to differ materially from these forward- looking statements, and Noble does not assume any obligation to update these statements. Also note, we are referencing non-GAAP financial measures on the call today. You can find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation in our earnings report issued yesterday and filed with the SEC. Now I'll turn the call over to Robert Eifler, President and CEO of Noble.

Thanks, Ian. Welcome, everyone, and thank you for joining us as we present our results for the second quarter. Today, I'll walk through our financial and operational highlights, recent commercial wins, our perspective on the market, including our semiannual outlook on regional deepwater demand and wrap up with our fleet strategy. Then I'll hand it over to Richard to cover the financials before I return with some closing remarks and open the line for Q&A. Starting with Q2, we delivered strong financial results with adjusted EBITDA of $282 million and free cash flow of $107 million. Over the past 2 years, our capital return program has been a key element of our strategy. We affirmed that commitment this quarter, returning an additional $80 million to shareholders through our $0.50 per share quarterly dividend. Yesterday, our Board declared a $0.50 per share dividend for the third quarter, now eclipsing $1.1 billion in capital return since Q4 2022 through dividends and share repurchases. On the integration front, we're approaching the 1-year anniversary of the Diamond acquisition, and I'm pleased to report that we've achieved our $100 million synergy target ahead of schedule. I want to thank the teams across the organization who have made our integration efforts so successful. At this point, the heavy lifting is behind us, and our focus now is squarely on optimization. And I'm proud to say that we have already reached a point where we are truly better than the sum of our parts. Turning to commercial activity. Our contracting momentum continued this quarter. Building on the transformative awards that we announced in April, we have subsequently secured six new contracts since the last earnings call as detailed in our fleet status report published yesterday. First, on the deepwater front, the Noble Stanley Lafosse was extended by…

Good morning or good afternoon, all. In my prepared remarks today, I will review our second quarter results, provide a brief update on our integration progress and then discuss our outlook for the remainder of the year as well as some high-level perspectives around 2026. Starting with our quarterly results. Contract drilling services revenue for the second quarter totaled $812 million. Adjusted EBITDA of $282 million, and adjusted EBITDA margin was 33%. As expected, Q2 revenue and adjusted EBITDA was sequentially lower, primarily due to planned out-of-service time for the Noble Sam Croft FPS and rigs rolling off contract during the quarter into a softer spot market. Q2 cash flow from operations was $215 million. Net capital expenditures were $110 million and free cash flow was $107 million. Included in the Q2 free cash flow is approximately $16 million from the closing of the Scirocco sale. The Meltem sale closed in early Q3 for the cash proceeds of approximately $25 million. As summarized on Page 5 of the earnings presentation slides, our total backlog as of August 5 stands at $6.9 billion, which includes $1.1 billion that is scheduled for a revenue conversion for the remainder of the year with $2.3 billion and $1.6 billion scheduled for conversion in 2026 and 2027, respectively. As a reminder, these figures exclude reimbursable revenue and revenue from ancillary services. We're very pleased with the progress of the Diamond integration and have now achieved our stated synergy cost target of $100 million. I'd like to echo Robert's earlier comments and thank our employees for the great work in achieving this milestone ahead of schedule. On fleet management, the moves outlined by Robert around the Globetrotter II, the Highlander and the Reacher, highlights our commitment to managing the business to maximize cash flow. While these…

Thank you, Richard. To reiterate, we're seeing signs that the deepwater market could firm up nicely by the second half of 2026 or 2027, but in the meantime, we are managing the business from a cost and cash flow discipline perspective for the flatter market presently at hand. We remain committed to and confident in a stable dividend. Thus, shareholders in Noble have the unique benefit of being paid to wait for the next leg up in the cycle. While late 2026 is still a ways out and with perennial macro uncertainties and volatility continuing to shape upstream spending, our current backlog, coupled with the active dialogue we're having with customers on a global basis gives us confidence in soon substantially derisking an annualized free cash flow run rate of $400 million to $500 million by the second half of next year, even in a scenario where current trough levels of demand linger past 2026. Today, we are keenly focused on securing the very small handful of key remaining contracts that would be necessary to complete that picture, while continuing to deliver the service integrity and value every single day that our customers expect and require from Noble. With that, operator, we're now ready to go to questions.

[Operator Instructions] Your first question comes from the line of Arun Jayaram with JPMorgan.

I was wondering if we could unpack a little bit about around the guidance update, you're lowering your top line guidance by about 3%, but tweaking higher your EBITDA guide by about 1%. So maybe you could just help us unpack kind of the moving pieces there.

So I think on the last conference call, I think we softly guided to the low end of the revenue range. And you know, I think unfortunately, we had a couple of options or specific options that [ should be decided ] that it's happening through this year. And so I think that [ talks widely ] because the top line is down. I think also from an EBITDA perspective, I think just strong customer management across the board. [indiscernible] if you will, which is why the top line seems down a little bit at the midpoint of the EBITDA slightly.

Got it. Got it. So cost management, the driver of that. Got it. Got it. Okay. Great. And then maybe for Robert, you highlighted the organization's focus from a marketing perspective on the BlackRhino, Viking and Gerry De Souza. Obviously, the outlook, which is kind of consistent with your peers is for a broader set of opportunities kind of emerging later in '26 and '27. So talk to us about kind of your strategy around those 3 rigs because that can be a decent swing factor as we think about your earnings power next year?

Yes, sure. And that's right. We're highly focused on those 3. I mentioned at the end of my prepared remarks where we think we can get run rate in having probably 2 of those 3 contracted [ as it is ] a key part of that. What I would say is we have a very strong line of conversation behind all 3 of those rigs. And I think that, that fits in -- while we've had perhaps a slightly more muted tone on the outlook -- on the market outlook, we do see the big projects going through definitively and we are extremely encouraged by the level of conversations we're having around bigger projects and in search of the higher quality rigs. So I think what we've seen -- and [ this was ] the question, but I think what we've seen here, especially in the last 3 months, is a little bit of a disappointing level of demand at the lower end spectrum of rigs globally, but with very little change on demand for the higher-end rigs.

Your next question comes from the line of Fredrik Stene with Clarkson Securities.

So I wanted to touch a bit first, a bit more specifically on Brazil. Clearly, you have, as you said in your prepared remarks, quite a decent exposure to South America in general. But right now, there are several tenders, etc, going on down in Brazil, Buzios, [indiscernible], Tupi, etc. You have I think, 1 rig rolling off in late '26, 1 in early 2027. How do you think about the recontracting opportunities for those units in particular? And are you planning to keeping them down in Brazil?

Yes. So I think we think about Brazil is at worse, flat and more likely, probably up a rig or 2 on rig demand. Obviously, with 30 of the 35 rigs in country, Petrobras will be the one who determines that .Then there, I think the narrative from them is positive. You've got the Buzios tender right now, and there are a lot of moving parts. They firmed off a handful of rigs already. But the way they kind of shape that tender and then move forward from there is very important, and it's just a little bit too early, I think, to have of kind of, I guess, a factual opinion on where they go. But we're planning for Petrobras to effectively be flat on rig count through time and then with some upside, as we mentioned, outside of Petrobras in Brazil. So we're pretty -- and then obviously, further north, there's a an immense amount of activity. It's a core region for us. And so we think South America right now is certainly a bright spot on the demand side.

Okay. That's very helpful. And then turning to supply. You have 3 rigs announced today that your holding for sale, one being in the definitive agreement already. The 2 others, I -- maybe you said it in the prepared remarks, but are those targeted to be retired from the drilling fleet? Or are you potentially selling to, call it, competitors or niche markets where you don't have any presence? And as an add-on to that, you also talked about rigs in your fleet now having, call it, individual stacking plants, etc, if there is prolonged downtime. But if you don't find opportunities for some of those rigs, can you identify potential further retirement candidates also beyond the Globetrotter I, as you mentioned.

Yes. So the Highlander will go to a drilling project, and we don't have a conclusion on the Reacher or the GT II, but we would not anticipate those are sold for drilling purposes. So we would not anticipate that the Reacher or Globetrotter that we would be competing against those later. The Highlander well go to drilling. I would reiterate on the second part of your question, what we've done already with the Meltem and the Scirocco, and we mentioned that the Globetrotters, those are effectively competing for intervention work with the sole exception of 1 or 2 places in the world that really need the Globetrotter capabilities for drilling the likes of Black Sea. And then I think being rational on the jackup side as well, we're just big believers that the option value of hoping for a better market at present is more expensive than it has been in times past. And we've said for years that we're running this company to generate cash and our fleet rationalization policy has been really in keeping with that. So what else could be out there? We mentioned the GT I but I think from there, if we've done what we think we need to do. Obviously, we can be -- we'll continue to be rational and we'll continue to look forward at what we see and specific opportunity set for a given rig and make decisions, and continue to be rational as we move forward.

Your next question comes from the line of Eddie Kim with Barclays.

So you provided a very constructive medium-term outlook in your walk through the regions but indicated some near-term kind of softness here. We've seen leading edge day rates on recent [ Mota ] contracts in the low 400s. Just curious on your expectation on where that pricing could go for upcoming contracts later this year. Do you think rates kind of hold firm here in the low 400s? Or could they even see a downtick lower, just given the near-term softness we're seeing right now? Just curious on your thoughts there.

Yes. I mean, I think -- thanks, Eddie. I think rates are in low mid 400s like you said. There hasn't -- to my knowledge, there hasn't been a single example of a 2 BOP Tier 1 rig below that range. Our outlook is that there should be some incremental rigs demand by late '26 hopefully, and I can't imagine someone dropping rates with that outlook, but who knows? I do you think you have -- because of the -- you've got a little bit of a funny dynamic where there's a number of big projects coming on in late '26 and '27, with probably a drop in demand in the interim. So people like to talk about gap filler work, that kind of stuff, who knows. I think you could have some lower rates. But I think -- I don't think that's representative of a broader market view if you pull in late '26 and '27 earnings potential.

Got it. That's very helpful color. My follow-up is somewhat related. I think you said in the prepared remarks that there's a very credible path back to UDW rig count back up to 105, I think towards the back half of next year, assuming stable macro conditions. Fair to say that there is also a very credible path back to leading-edge day rates sort of in that mid- to high 400s level on contract announcements we might see in the back half of next year?

It's a great question. I wish I knew the answer. I think the way we view it is that we're in a little bit of a lull that's been created by a lot of macro noise right now. So if you want to -- I would make the claim that if we're now just below 100 working rigs on the floater side, on the UDW side that perhaps -- we just take the Brent curve that perhaps kind of the normalized demand level with current Brent curve, which should be 100 to 105, that kind of range. And we've counted up projects and I think see a path to the higher end of that range. So yes, I think that is at a minimum stabilization, and there is absolutely a path where rates tick back up from here. We're going to have to wait and see what happens in the interim. You can map out of a relatively large slice of the demand through big projects. But there is always just enough other out there that makes these things pretty hard to predict. And I kind of mentioned it earlier around the lower spec -- the demand requiring lower spec assets. But in my opinion, it's the other that's created a softer market here recently than I think anyone was anticipating. So it's a little early for these prediction, but we're certainly hopeful here that we get back to a much more normalized level by the end of next year. And then I guess I would add on the thoughts that we kind of made in the prepared remarks, but we just feel very strongly that with our fleet, our current contract set and then a pretty limited need for additional contracts that we can set ourselves up here for some pretty meaningful cash flow. We mentioned $400 million to $500 million in the prepared remarks with effectively a flat market from here, even maybe day rates down a small tick. But effectively, if what we see now is the new reality, we still think that we can generate meaningful cash flow for our investors and we've given a lot of data out for cause for optimism that we would actually be up from that.

Your next question comes from the line of Greg Lewis with BTIG.

Yes. I feel like I asked this like once a year, but could you kind of remind us the timing of the Exxon rig resets and then maybe how we should be thinking about that? I believe it's in October, how we should be thinking about that versus, say, where it was, when it was reset, I guess, a few months ago?

Yes. It's March 1 and September 1 are the dates that the new rates go into effect. And so those rates are respectively set 3 to 5 months prior to when they go into effect. I would say that, that mechanism has worked extremely well and it has tracked the market since we came up with the CEA. And so you're talking about a September rate that will go into effect that was set 2 or 3 months ago, and so we don't give the rates out, but I think there's obviously [ hopeful ] ties. And I think that, that mechanism has really tracked the market very closely.

And then -- and I felt like, Robert, you mentioned kind of dual BOP, which is what those are. So it's safe to assume that excludes kind of like a -- it definitely sounds like it excludes sixth-gen rigs, but maybe even lower end seven-gen rigs?

That's correct. That's absolutely...

Okay. Great. And then I did have a broader question. Obviously, there were some big news yesterday with some consolidation in the jackup market. Clearly, the acquirer has not historically operated in the North Sea. Does this -- M&A is sometimes good for a sector sometimes bad. Any kind of view on how this impacts the jackup market and realizing you've been scaling down your jackup fleet over the last couple of years, but any kind of view how -- does this do anything to change how you're thinking about your jackup fleet post that M&A deal?

No, not really, honestly. I mean, we have the 3 rigs outside of the North Sea that we're marketing aggressively. And then yes, there's obviously some overlap with the North Sea in this M&A deal. But we're -- it doesn't change our demand -- I mean, sorry, [indiscernible], but honestly, no, it doesn't do a whole lot to change our views on anything. I'm happy for the companies, and I think it was probably a great deal and win-win, but it doesn't really -- I don't think it spurs action from our side necessarily.

Your next question comes from the line of Doug Becker with Capital One Securities.

Robert, you've laid out that Q1 drillships are still in the low 400 to mid-400 range. Have you seen any material changes to some of the other factors that can affect economics like mob or demob fees or capital reimbursements. Just trying to look a little deeper in terms of the economics in the current environment.

Yes. I mean, look, contract terms are effectively correlating with day rates. However, I would say that if you're talking about a wider spectrum of potential day rates, so the awful years that had 2 handles on them all the way over to kind of some world with 5 handles where there is the true shortage of rigs. I don't think the change between high 400s and low 400s is particularly meaningful on the broader contract term scale. So yes, there will be a bit of economic leakage probably today versus when we were knocking on the 500 door. But I don't think that's a meaningful change so far.

Fair enough. And you've touched on this a little bit, but just on some of the options that are outstanding, just any general commentary in terms of option exercise as we think about those rigs going forward.

Yes. I think we made the assumption for 2 or 3 years that all options would be exercised. And I think today, we will make the assumption that I'm just -- I have no idea, I'm just going to throw, out 50% to 75% are exercised and hopefully towards the higher end of that. But maybe another way to put that is that there's definitely going to be -- if you look across the full industry spectrum of options. There's going to be a non-negligible number that probably are not exercised. We suffered from that a little bit on our 2025 numbers, where mid- to late last year, we were quite certain that a couple of them would be optioned -- would be exercised that ultimately were not.

Your next question comes from the line of David Smith with Pickering Energy Partners.

So a lot of mine have been answered. I'm going to step back with just a little bigger picture question. In past cycles, we typically saw floater contract lead times move in tandem with utilization and backlog. In the past few months, we've seen operators locking in multiyear contracts with 12- to 24-month lead times even as near-term demand looks softer and the rig count trends lower. It's creating multi-quarter gaps between contracts for some rigs, a dynamic that seems fairly uncommon compared to prior cycles. I was curious if this strike you as unusual. And if you have any thoughts on what is driving that out-year contracting behavior?

Yes, that's a great observation, Dave. And we agree with you. I mentioned earlier a little bit that it is kind of a unique -- because we're asked about day rates, and it is a little bit of a unique situation where I think whether you're talking to a drilling contractor or a service company, everybody sees some demand on the horizon here in late '26 and '27. And there's been a disconnect between some long lead provider and the national service providers for some time. And so it is creating a kind of a different situation than we're accustomed to. I think that part of this is -- look, our understanding is that for these -- all the projects that are being sanctioned and moving forward, obviously, the math works here in the kind of 60s range for Brent. So I think you're seeing that dynamic play out as major projects move forward. And I think you're seeing that on the back end of so much noise, macro noise and also a persisting commitment to capital discipline for our customers that it's creating slightly different dynamics than what we're used to. And the core -- you're right, the correlation on lead time has kind of fallen apart here. But we take all that as a good sign. We went through the global view, and we're optimistic that we can get back to what I would call a more normal level for -- a more normal level of activity, kind of 100 to 105 working UDW rigs.

I appreciate it. And a follow-up if I may. Just kind of relates to Eddie's question earlier. But for the rigs that are facing multi-quarter gaps between firm term contracts. Do you see a risk that bidding strategies become more aggressive to fill in those gaps? And if so, do you think that more competitive pricing for short-term and near-term work might influence broader pricing expectations or do you think it's just going to result in a greater bifurcation for short-term, near-term versus longer-term work?

Yes. I mean, for sure, I think you're going to see gas sort of work where people are willing to take almost any price or take a discount, maybe a better way to say it, but I just don't think that affects the broader pricing strategies for the companies. I don't think it will affect ours. And I think back to this funny dynamic we have right now, everybody sees it, and we're one of the last to go on this earnings season and whether you're talking about drilling, tractor or a service company, everyone is talking about the same dynamics. And so I think that's really meaningful and important. And I think people are going to price as they see the market and people generally see a bit of an uptick here in starting late '26. So I think of the gap filler stuff as more noise than I do of something that's going to drive rates.

Really appreciate the color. Congrats on the quarter and the better cost outlook.

Your next question comes from the line of Noel Parks with Tuohy Brothers.

I was wondering just given some of your comments about the marketplace so far, do you see -- or have you considered any revisiting of the maintenance and upgrade schedule as you look at what's still some near-term uncertainty about white space being taken up balanced against, as you pointed out, the pretty consistent industry optimism in '26 and '27.

Yes. I think what I would say is we've -- we talked earlier, of course, about rationalization of the fleet and our view on that and the carrying cost of some of this "option" value. You're asking more specifically about the working rigs. And so I would say that we had -- we haven't brought revenue down, EBITDA. And so we've managed costs very closely. And we -- in the previous call, we mentioned that we kind of take -- if you want to divide things up between 6-month readiness and 1-year readiness, that kind of view. We've kind of taken a 6-month readiness on a couple of units, which we think is a good balance between present costs and marketability. And we feel we've been highly focused on managing costs, and we're happy with the decisions we've made around the -- really more on the flow side on the couple of units that we seek work for, but maybe with a bit of a gap before that work starts.

Great. And I'm just wondering if with BP's announcement of their big discovery at Boomerang offshore Brazil. Do you have any sense of whether that might help sort of affirm or accelerate what we've seen as a little bit of a positive drift towards exploratory dollars and drilling in the industry.

Yes. I mean all discoveries are good for our business. And my longer-term view is very firm around the need for oil and gas produced from offshore wells. There is a gap that we will eventually get to, have to assume an oil demand, obviously. But if history is any guide, I think I'm very confident that there's a gap between discovered barrels and needed barrels coming from offshore and we thought that dynamic might start playing out this year. It's been pushed off to the right. There's a lot of macro noise, but I remain extremely confident that the need for our services to increase offshore production is imminent and will come in the next few years. So you're starting to hear more about reserves, reserve life, reserve replacement from our customers. And I think this is one of our biggest customers and them highlighting that this is the best exploration year in 10 years, I think is another data point that there is a meaningful shift back to offshore globally that's happening right now.

At this time, there are no further questions. I will now turn the call back over to Ian MacPherson for closing remarks.

Thank you, everyone, for joining us today. We appreciate your interest, and we look forward to speaking with you again next quarter. Have a good day.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.