Noble - Earnings Call - Q2 2025

Transcript

Speaker 6

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's second quarter 2025 earnings call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I would now like to turn the call over to Ian Macpherson, Vice President of Investor Relations. Please go ahead.

Speaker 5

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 Contract, and Julie 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.

Speaker 0

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 semi-annual outlook on regional deepwater demand, and wrap up with our fleet strategy. 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 an adjusted EBITDA of $282 million and a free cash flow of $107 million. Over the past two 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 returns since Q4 2022 through dividends and share repurchases. On the integration front, we're approaching the one-year anniversary of the Diamond Offshore Drilling 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. I'm proud to say that we've 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 its current customer in the U.S. Gulf for five additional wells, spanning approximately 14 months and keeping the rig contracted through August 2027. There is an option for an additional five wells at mutually agreed rates. Next, the Noble Viking received a one-well contract with Total in Papua New Guinea, scheduled to commence in Q4 in direct continuation of its Brunei campaign. This estimated 47-day program is valued at $34 million, including mobilization, demobilization, and NPD usage, but excluding a modest performance bonus.

This will be the first drillship to operate in Papua New Guinea in over 30 years, and the first ever ultra-deepwater rig to do so. We're honored that Total has entrusted us with this high-impact exploration well, which includes options for three additional wells in the region. Finally, on the deepwater side, the Noble Globetrotter One, having recently completed its campaign in the U.S. Gulf, secured a two-well contract with OMV in the Black Sea. This contract is planned to begin in Q4, with an estimated duration of approximately four months and a total contract value of approximately $82 million, including a day rate of $450,000 plus mobilization and demobilization fees. The rig's unique design provides a distinct advantage for transit into and out of the Black Sea.

As a reminder, this Black Sea program is a specific niche market opportunity, but we have otherwise removed the Globetrotters from competitive bidding into drilling programs globally. In addition to these deepwater awards, we also secured several recent contracts in our jackup fleet that highlight the versatility of our harsh environment rigs and our ability to support both traditional and energy transition projects. First, the Noble Innovator was awarded a six-well contract with BP for the Northern Endurance Partnership carbon capture and storage project in the UK North Sea. The program is expected to commence in Q3 2026, in direct continuation of our current contract with BP, at a day rate of $150,000, with a minimum firm term of 387 days plus two optional wells.

Subsequently, the Noble Intrepid was awarded a two-well program with BP for additional Northern Endurance Partnership carbon capture and storage wells, also at $150,000 per day. Intrepid's contract is scheduled to commence in April 2026 for an estimated duration of 160 days plus options. We're very proud to support BP with this critical infrastructure project that underpins the UK's carbon storage ambitions. Lastly, the Noble Resilient secured a 92-day accommodation services contract at the Inch Cape Offshore Wind Farm in the UK North Sea. This contract is scheduled to commence within the next few weeks and is valued at approximately $6.5 million for the firm 92-day term, with options to extend. Year to date, we have now secured new contracts with a total contract value of $2.8 billion, and our total backlog as of August 5th stands at $6.9 billion.

As a reminder, our backlog position assumes 40% of available performance revenue realized on a combined basis under our recent long-term contracts with Shell and Total. We continue to pursue a number of promising opportunities to build on this recent momentum and look forward to sharing further updates as they materialize. Before we move to the market outlook, I'd like to highlight two key contract startups in Southeast Asia and the Americas that required significant planning and coordination to execute safely and on time. I want to thank the teams involved for their hard work in bringing these projects online. First, in the Philippines, the Noble Viking commenced a critical three-well program for Prime Energy in June to extend the life of a key gas field, an important part of the country's broader push for energy security and independence.

Following the recent award with Total, the Viking could remain active through most of the first quarter next year if options are exercised, with a robust pipeline of future opportunities in the region thereafter. Next, in Suriname, the Noble Developer recently kicked off an important three-well development campaign for Petronas in July, returning to a region with a growing pipeline of development activity for this class of rig. Now on to the market outlook, including our semi-annual review of key deepwater geographic markets. Amidst significant macro uncertainty and upheaval this year, between tariffs, Middle East conflict, and Brent crude prices that have ranged between the low $60s and the low $80s per barrel, the demand characteristics for offshore drilling have stayed comparatively on trend.

While we have seen intensifying pressure on 2025 upstream CAPEX, resulting in incrementally more near-term gaps for rigs, we have also seen a crystallization of firming conditions by H2 2026 and into 2027. On the UDW demand side, the global contracted rig count currently stands at 97 rigs, which is roughly flat compared to recent quarters, but down from the recent peak of 105 to 106 during 2023-2024. We will still probably see a few more idle units over the next few quarters as scheduled rollovers are likely to outstrip visible contract starts and extensions. This near-term slack in the market continues to pressure day rates, which are now generally in the low to mid-$400s per day for Tier 1 ultra-deepwater drillships. Geographically, the recent deepwater demand trend has been shaped by continuing strength in South America, contrasted with softness in West Africa.

However, visibility for a potential rebound in West Africa is promising and hopefully drawing nearer. Starting first in South America, where contracted UDW demand stands at 43 total units, including 35 rigs in Brazil, 5 in Guyana, 2 in Suriname, and 1 in Colombia. This is a highly important region for Noble, as we have 2 rigs working in Brazil and 7 out of the 8 rigs contracted across Guyana, Suriname, and Colombia. Visibility throughout the region remains highly encouraging. Starting with Petrobras in Brazil, a strong outlook is supported by recent tenders covering existing development drilling throughout Búzios, Mero, and Tupi, as well as potential for new frontier exploration activity in the recently licensed Foz do Amazonas basin further to the north.

These, combined with Shell's recent FID at Gato de Mato, Equinor's recent drillship tender, very significant recent exploration success from BP announced just this week, plus miscellaneous demand from one or more smaller operators, collectively all frame a very exciting outlook for Brazil for years ahead. Elsewhere throughout South America, we are tracking potential floater programs throughout Suriname, Trinidad, Colombia, Uruguay, and the Falklands, with varying probability and timing factors. Overall, the deepwater market in South America continues to show extraordinary depth and breadth of demand, which should keep the region in growth mode. The U.S. Gulf has softened recently with 21 contracted UDW rigs today, down from 22 to 24 rigs last year.

Depending on how the spot market plays out, we may see activity drop slightly further in the back of this year, although current indications from customers suggest that the rig count could normalize back toward around 20 UDW rigs next year. That said, demand on the U.S. Gulf tends to be a bit more dictated by spot market drivers and is sensitive in that regard to commodity prices as well. Our primary marketing priority in the Gulf is the Noble Black Rhino, which will finish its current contract in the next month or so. We are constructive on the rig's long-term outlook in 2026 based on direct conversations we are having with clients, but we would not be surprised to see the rig encounter some near-term whitespace in the meantime.

Next, on to West Africa, where current UDW demand is 12 rigs, similar to recent quarters, but materially below the 17 to 20 range that prevailed throughout 2023 and the first half of 2024. Angola remains steady at six rigs, while Namibia and Nigeria have declined to just one and zero rigs respectively, representing a combined decrease of six rigs compared to last year. The good news is that visibility for resumed growth in the region is increasingly tangible. While West Africa and Mozambique comprise only 12% of total deepwater rig count today, the region's corresponding share of open demand is two times that level at over 25%. Several prominent IOC tenders appear to be progressing towards contract awards with 2026 and 2027 start dates.

These anticipated fixtures should be supportive of a UDW rig count back toward the mid to high teens, or conceivably higher if and when Namibia eventually regains momentum. Namibia for now does not factor as prominently in the near-term open demand picture as other areas like Nigeria, Ghana, Côte d'Ivoire, and Mozambique, but it should ultimately progress back toward a more consistent multi-rig basin in the fullness of time. Additionally, we are seeing potential incremental exploration activity in adjacent South African blocks, which could materialize as early as 2026. The Mediterranean and Black Sea have remained steady with eight to nine UDW rigs. However, the big positive surprise in this region recently has been Turkish Petroleum's acquisition of two more drill ships from sideline capacity, which will increase their captive fleet from four to six drill ships and add two more units of long-term captive demand in the region.

Open demand throughout the Med appears otherwise supportive of stable activity levels, excluding the oscillations in the Black Sea and the structurally upsized demand from Turkey. Asia Pacific plus India has remained muted and is now down to four UDW units compared to five earlier this year and seven to eight rigs last year. Despite the recent decline, open demand for multiple rigs across India, Southeast Asia, and Australia suggests a modest upward bias in activity over the next one to two years, although some of the incremental rig needs are likely to be satisfied by lower spec equipment. Lastly, the harsh environment North Sea and Norway market currently represents six units of UDW demand and 19 units of total floater demand, including midwater, both of which are down by one rig compared to earlier this year.

Two of our North Sea semis, the Great White and the Endeavor, have rolled off contract recently with no visible work opportunities for the balance of this year. Upstream customer consolidation policy and fiscal headwinds continue to suppress spending, and there has also been some incremental deferral of P&A and intervention programs since earlier this year. That said, most of the North Sea and Norway floater fleet is copiously contracted into 2027 and beyond. Moreover, there is potential for one harsh semi requirement in Canada, which is currently an inactive market.

Tying all this together, although the next several quarters continue to be characterized by a variety of pluses and minuses on the demand side, which appear to shake out to a roughly flat market, we continue to believe that the bottoms-up view supports promising upside by late 2026 or 2027, including a very credible path back toward a contracted UDW rig count of around 105, assuming reasonably stable macro conditions. As we've seen over the past 12 to 18 months, timing risk really continues to be the key wildcard as many FIDs and rig awards have been drifting to the right. Hence our focus on judiciously managing our costs and active fleet posture based on current market realities. Now, I'll comment briefly on our contract position and objectives.

We've made very good headway toward contracting our 15 high-end drillships, and we are now principally focused on the Noble Black Rhino, Noble Viking, and Noble Jerry de Souza as key remaining priorities, all three of which have very robust opportunities under discussion with customers for programs commencing in 2026. Moving down the fleet with a decision to dispose of the Noble Globetrotter Two, the Noble Globetrotter One still remains in consideration for several multi-year well intervention scopes, which could potentially follow the rig's Black Sea drilling program. If none of these intervention opportunities comes to fruition, then we will likely move to dispose of the Noble Globetrotter One as well. Four of our eight semi-submersibles are well contracted next year, while the Deliver, Great White, Endeavor are currently idle and Apex rolling next month.

We're pursuing active leads for all four of these units around the world, with expected starts varying throughout 2026 and 2027, and each is subject to individual stacking plans over the interim term. We'll continue to carefully evaluate stacking costs vis-à-vis the opportunity set, especially with older rigs. Now on to jackups. In our harsh environment Northern Europe market, current demand is 28 jackups. This demand level has fallen off by about three rigs compared to last year, and forward visibility for 2026 continues to be clouded by fiscal and regulatory headwinds. We are happy with several of our recent contract wins, including additional carbon capture and storage and wind farm construction support activity in the UK, in addition to expanding our customer book in Norway with the Intrepid's Diamond Offshore Drilling contract.

Overall, however, we expect muted market conditions throughout the region to linger until policy-driven impediments are removed, particularly in the UK. That said, our jackup earnings contribution is disproportionately weighted to our well-contracted units, and we do not anticipate material earnings erosion from the overall jackup fleet segment compared to current levels. Wrapping up, on the supply side, we have recently closed the disposals of the cold stack drillships Pacific Scirocco and Pacific Meltem, permanently removing those units from the drilling market. We are now moving forward with the disposal of the Noble Globetrotter Two, in addition to the jackup Noble Highlander, for which we have entered into a definitive agreement to sell for $65 million, and the jackup Noble Reacher, which is also now held for sale.

For additional context, the Reacher is the lowest capability jackup in our fleet, having worked exclusively in accommodation mode for the past few years, and the rig would require meaningful capital to be drilling ready again. These actions reflect our continued focus on maintaining a high-spec competitive fleet and managing our costs and active capacity as judiciously as possible in order to maximize cash flows for our shareholders. To underscore this point, while we don't know with exact precision, our best estimate is that the current combined run rate costs for idle/slash stacking time across the largest drilling contractors is likely approaching $800 million to $1 billion on an annualized basis. By these estimates, idle costs for floaters alone represent a surcharge of around $30,000 to $35,000 per day on average across every one of the working floater rigs in the global fleet.

With our focus on cash flow maximization and returning capital to shareholders, we are taking aggressive action to reduce Noble's exposure to this surplus cost burden. In other words, our recent impending capacity rationalizations are instantly accretive as these units have not contributed positive economics in recent years. As we look ahead to a near-term flat market with promising upside optionality in the years ahead, we are optimally positioning the fleet for either a flat market or growth market with effectively no relevant earnings attrition. With that, I'll pause here and turn it over to Richard now to discuss the financials. 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 was $282 million, and adjusted EBITDA margin was 33%. As expected, Q2 revenue and adjusted EBITDA were sequentially lower, primarily due to planned out-of-service time for the Noble Samcroft SPS and rigs rolling off contract during the quarter into a softer spot market. Q2 cash flow from operations was $216 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 this Q2 sale. The Meltem sale closed in early Q3 with a cash proceed of approximately $25 million.

As summarized on page five of the earnings presentation slide, 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 Noble Globetrotter Two, the Noble Highlander, and the Noble Reacher highlight our commitment to managing the business to maximize cash flow.

While these decisions are not taken lightly, we can no longer justify keeping these rigs in our fleet when weighing the ongoing stacking costs and reactivation capital against the opportunity set. Referring to page 10 of the earnings slide, we're updating our full year 2025 guidance and policy. First, total revenue is lowered to a range of $3.2 billion to $3.3 billion. This update aligns with our commentary on the prior call around trending to the lower end of the initial range as we see whitespace persist in the second half of the year, specifically on rigs we previously thought would see option exercises that did not materialize. Second, the guidance range for adjusted EBITDA is narrowed to the upper end of the previous range, now standing at $1.075 billion to $1.15 billion. This is driven by decent first half results and strong cost management across the business.

The lower half of this revised range is effectively fully contracted based on year-to-date results and remaining 2025 backlog. Third, we are increasing capital expenditures, excluding customer reimbursements, to a range of $400 million to $450 million. The increase reflects capital tied to the recent long-term awards. Rebillable CapEx for 2025 is expected to total approximately $25 million, with $10 million incurred in the first half. Looking towards 2026, we currently would expect 2026 capital expenditures to be in the ballpark of around $450 million, which includes the capital acquired for the recent long-term awards. As we look ahead, we anticipate adjusted EBITDA to decline sequentially in Q3, primarily due to contract rollovers and planned downtime for the Noble Venture. These impacts will be partially offset by the Noble Developer contract startup in Suriname and the Noble Samcroft working following her Q2 SBA.

If we zoom out and bring 2026 into view, we remain constructive on the long-term market despite whitespace that is expected to persist well into 2026. Given this, we expect quarterly EBITDA to trend lower over the next four quarters relative to the first half of 2025, but expect a material rebound starting in the second half of 2026, supported by the startup of new long-term contracts in parallel with rising deepwater demand levels. In the meantime, we are taking a disciplined approach to managing our business that is calibrated to the realities of a nearer-term flatter demand environment. With that, I'll hand it back to Robert for closing remarks.

Speaker 5

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. 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 de-risking an annualized free cash flow run rate of $400 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.

Speaker 6

At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Arun Jayaram with JP Morgan. Your line is open.

Speaker 7

Yeah, good morning, gentlemen. I was wondering if we could unpack a little bit about the guidance update. You're lowering your top line guidance by about 3%, but tweaking higher your EBITDA guide by about 1%. Maybe you could just help us unpack the moving pieces there.

Speaker 0

I think on the last conference call, I think we softly guided to the lower end of the revenue range. Unfortunately, we've had a couple of options or specific options which were decided to have to be revisited. I think that talks why the top line is down. I think from an EBITDA perspective, I think it's a strong customer management. Across the board, I think it's unimportant. I think it's that disconnect, which is why the top line's been down a little bit and the midpoint of the EBITDA now slightly.

Speaker 7

Got it, got it. Cost management, the driver of that. Got it, got it. Okay, great. Maybe for Robert, you highlighted, you know, the organization's focus from a marketing perspective on the Noble Black Rhino, Noble Viking, and Noble Jerry de Souza. You know, obviously, the outlook, which is kind of consistent with your peers, is for a broader set of opportunities kind of emerging, you know, later in 2026 and 2027. Talk to us about kind of your strategy around those three rigs because that can be a decent swing factor as we think about, you know, your earnings power next year.

Speaker 0

Yeah, sure. That's why we're highly focused on those three I mentioned at the end of my prepared remarks where we can get run rate, and having probably two of those three contracted is a key part of that. What I would say is we have a very strong line of conversations behind all three of those rigs. I think 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.

I think what we've seen, I know it's in part of the question, but I think what we've seen here, especially in the last three 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 demands for the higher-end rigs.

Speaker 7

Great. Thanks a lot, gentlemen.

Speaker 0

Thanks, everyone.

Speaker 6

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

Speaker 4

Hey, Robert and team. I hope you are having a nice day so far. I wanted to touch a bit first, a bit more specifically on Brazil. Clearly, you know, you have, as you said in your prepared remarks, quite a decent exposure to South America in general. Right now, there are several, several tenders that are going on down in Brazil, Búzios, Mero, Tupi, et cetera. You guys have, I think, one rig rolling off in late 2026, one in early 2027. How do you think about the recontracting opportunities for those units in particular? Are you planning to keep them down in Brazil?

Speaker 0

Yeah, so I think we think about Brazil as at worst flat and more likely probably up a rig or two on rig demand. Obviously, with 30 of the 35 rigs in the country, Petrobras will be the one who determines that. I think the narrative from them is positive. You've got the Búzios tender right now, and there are a lot of moving parts. They've firmed up a handful of rigs already, but the way they kind of shape that tender and then move forward from there is very important. It's just a little bit too early, I think, to have a factual opinion on where they go. We're planning for Petrobras to effectively be flat on rig count through time and then with some outsiders, as we mentioned, outside of Petrobras in Brazil.

We're pretty, and obviously, further north, there's an immense amount of activity at the core region for us. We think South America right now is certainly a bright spot on the demand side.

Speaker 4

Okay, thanks. That's very helpful. Turning to supply, you have three rigs announced today that you're holding for sale, one being in the definitive agreement already. The two others, 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? As an add-on to that, you also talked about rigs in your fleet now having called individual stacking plans, et cetera, if there is prolonged downtime. If you don't find opportunities for some of those rigs, can you identify potential further retirement candidates also beyond the Noble Globetrotter One, as you mentioned? Thanks.

Speaker 0

Yeah. The Noble Highlander will go to a drilling project. We don't have a conclusion on the Noble Reacher or the Noble Globetrotter Two, but we would not anticipate that those are sold for drilling purposes. We would not anticipate that the Noble Reacher or the Noble Globetrotter, that we would be competing against those later with the Noble Highlander, will go to drilling. I would reiterate on the second part of your question, what we've done already with the Pacific Meltem and the Pacific Scirocco. We mentioned that with the Noble Globetrotters, those are effectively competing for intervention work with the sole exception of one or two places in the world that really need the Noble Globetrotter capabilities for drilling, like the White Sea.

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. We've said for years that we're running this company to generate cash. Our fleet rationalization policy has been really in keeping with that. What else could be out there? We mentioned the Noble Globetrotter One, but I think from there, I think we've done what we think we need to do. Obviously, we'll continue to be rational, and we'll continue to look forward at what we see in the specific opportunity set for a given rig and make decisions and continue to be rational as we move forward.

Speaker 4

All right. Thank you so much. I'll leave it at that.

Speaker 0

Thanks, Fred.

Speaker 4

Have a good day.

Speaker 0

You too.

Speaker 6

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

Hi, good morning. You provided a very constructive medium-term outlook in your walk through the regions, but indicated some near-term softness here. We've seen leading edge day rates on recent contracts in the low $400,000s. I'm 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 $400,000s, or could they even see a downtick lower, just given the near-term softness we're seeing right now? I'm just curious on your thoughts there.

Speaker 0

Yeah, I mean, I think, thanks, Eddie. I think rates are low to mid-$400,000s, like you said. To my knowledge, there hasn't been a single example of a 2BOP, Tier 1 rig below that range. Our outlook is that there should be some incremental rig demand by late 2026, hopefully. I can't imagine someone dropping rates with that outlook, but who knows? I do think you have a little bit of a funny dynamic where there's a number of big projects coming on in late 2026 and 2027 with probably a drop in demand in the interim. People like to talk about gap filler work, that kind of stuff. Who knows? I think you could have some lower rates, but I don't think that's representative of a broader market view if you pull in late 2026 and 2027 earnings potential.

Got it. That's very helpful, Colin. Thank you. My follow-up is somewhat related. I think you said in 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 $400,000 level on contract announcements we might see in the back half of next year?

That'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. 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 would 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. We've counted up projects and nothing can see a path to the higher end of that range. Yes, I think that is at a minimum of stabilization, and there is absolutely a path where rates kick back up from here. We're going to have to wait and see what happens in the interim.

You can map out 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. I kind of mentioned it earlier around the lower spend, the demand requiring lower spend assets. In my opinion, it's the other that's created a softer market here recently than I think anyone was anticipating. It's a little early for these predictions, but we're certainly hopeful here that we get back to a much more normalized level by the end of next year. I would add on a thought 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, we can set ourselves up here for some pretty meaningful cash flow.

We mentioned $400 to $500 million in the prepared remarks, with effectively a flat market from here, even maybe day rates down a small tick. Effectively, if what we see now is the new reality, we still think that we can generate meaningful cash flow for our investors. We've given a lot of data out for cost-share optimism that we would actually be up from that.

Got it. Great. Thank you. I'll turn it back.

Speaker 6

Your next question comes from the line of Gregory Robert Lewis with BTIG. Your line is open.

Speaker 2

Thank you. Thanks for taking my questions. I feel like I ask this once a year, but could you kind of remind us the timing of the Exxon rig reset and 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 a few months ago.

Speaker 0

Yes, it's March 1 and September 1 are the dates that the new rates go into effect. Incentive evidence rates are respectively set three to five months prior to when they go into effect. I would say that mechanism has worked extremely well, and it has tracked the market since we came up with the CEA. You're talking about a September rate that will go into effect that was set two or three months ago. We don't give the rate out, but I think it's obviously awfully tied. I think that mechanism has really tracked the market very closely.

Speaker 2

I felt like, Robert, you mentioned kind of dual BOP, which is what those are. Is it safe to assume that excludes kind of the, you know, like a, like a, it definitely sounds like it excludes sixth-gen rigs, but maybe even lower-end seventh-gen rigs?

Speaker 0

That's correct. That's how 2 BOP is.

Speaker 2

Okay, great. Thank you for that. I did have a broader question. Obviously, there was 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, sometimes good for a sector, sometimes bad, does 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? Any kind of view, any kind of view, does this do anything to change how you're thinking about your jackup fleet post that M&A deal?

Speaker 0

No, not really, honestly. I mean, we have the three rigs outside of the North Sea that we're marketing aggressively. There's obviously some overlap with the North Sea in this M&A deal. It doesn't change our demand outlook. Honestly, no, it doesn't do a whole lot to change our views on anything. I'm happy for the company to think it was probably a great deal and a win-win. It doesn't really, I don't think it spurs action from our side necessarily.

Speaker 2

Okay. Super helpful. Thank you very much.

Speaker 0

Thank you, Greg.

Speaker 6

Your next question comes from the line of Douglas Lee Becker with Capital One Securities. Your line is open.

Speaker 1

Thank you. Robert, you've laid out that Tier 1 ultra-deepwater drillships are still in the low $400,000 to mid-$400,000 range. Have you seen any material changes to some of the other factors that can affect economics, like MOB or DMOB fees or capital reimbursements? Just trying to look a little deeper in terms of the economics in the current environment.

Speaker 0

Yeah, I mean, look, contract terms are effectively correlated with day rates. However, I would say that if you're talking about a wider spectrum of potential day rates, the awful years that had two handles on them all the way over to kind of some world with five handles where there is a true shortage of rigs, I don't think the change between high $400,000s and low $400,000s is particularly meaningful on the broader contract terms scale. Yeah, there will be a bit of economic leakage probably today versus when we were knocking on the $500,000 door. I don't think that's a meaningful change so far.

Speaker 1

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

Speaker 0

Yeah. I think we made the assumption for two or three years that all options would be exercised. I think today, we'll make the assumption that I have no idea. I'm just going to throw out half to 75% are exercised, and hopefully towards the higher end of that. Maybe another way to put that is that there's definitely going to be, if you look across the full industry spectrum of options, a non-negligible number that probably are not exercised. We've 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 exercised, and ultimately were not.

Speaker 1

Got it. Thank you.

Speaker 6

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

Good morning. Thanks for taking my questions.

Speaker 0

Hey.

A lot of mine had 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 multi-year contracts with 12 to 24-month lead times, even as near-term demand looks softer and the rate 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, you know, strikes you as unusual and if you have any thoughts on what is driving that out-of-year contracting behavior.

Yeah, that's a great observation, Dave. We agree with you. I mentioned earlier a little bit that it is kind of unique because we were 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 2026 and 2027. There's been this disconnect between some long lead providers and then the actual service providers for some time. 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 all the projects that are being sanctioned and moving forward, obviously, the math works here in the kind of $60s range for Brent. I think you're seeing that dynamic play out as major projects move forward.

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 is creating this slightly different dynamic than what we're used to. The correlative rise, the correlation on lead time has kind of fallen apart here. 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 in kind of 100 to 105 working UDW rigs.

Appreciate it. A follow-up, if I may, just kind of relates to Eddie's question earlier. 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? If so, do you think that more competitive pricing for short-term and near-term work might influence broader pricing expectations? Do you think it's just going to result in a greater bifurcation for short-term, near-term versus longer-term work?

Yeah, I mean, for sure, I think you're going to see gap-filler work where people are willing to take an almost any price or take a discount, maybe a better way to say it. I just don't think that affects the broader pricing strategies for companies. I don't think it will affect ours. I think you 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. When you're talking about drilling contractors or service companies, everyone's talking about the same dynamic. I think that's really meaningful and important. I think people are going to price as they see the market, and people generally see a bit of an uptick here starting in late 2026. I think of the gap-filler stuff as more noise than I do of something that's going to drive rates.

Okay, I really appreciate the call. Congrats on the quarter and the better cost outlook.

Thanks, Dave.

Speaker 6

Your next question comes from the line of Noel Augustus Parks with Toni Brothers. Your line is open.

Speaker 1

Hi, good morning. 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 2026 and 2027?

Speaker 0

Yeah, I think what I would say is we talked earlier, of course, about rationalization of the fleet and our view on that and the carrying cost of some of this quote option value. You're asking more specifically about the working rigs. I would say that we've, you know, we had, you know, we brought revenue down, EBITDA up, and we've managed costs very closely. In a previous call, we mentioned that people wanted to divide things up between six-month readiness and one-year readiness, that kind of view. We've kind of taken a six-month readiness on a couple of units, which we think is a good balance between present costs and marketability.

We feel we've been highly focused on managing costs, and we're happy with the decisions we've made around really on the more of the floater side, on the couple of units that we see work for, but maybe with a bit of a gap before that one starts.

Speaker 1

Great. Thanks. 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?

Speaker 0

Yeah, I mean, all discoveries are good for our business. 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 after the same amount of oil demand, obviously. If history is any guide, I think, you know, I'm very confident that there's a gap between discovered barrels and needed barrels coming from offshore. 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. You're starting to hear more about reserves, reserve life, reserve replacement from our customers. I think it's one of our biggest customers.

Highlighting that this is the best exploration year in 10 years, I think, is another data point that there is a meaningful shift back offshore globally that's happening right now.

Speaker 1

Great, thanks a lot.

Speaker 0

Thank you.

Speaker 6

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'll 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.