Seadrill - Earnings Call - Q2 2025

Executive Summary

• Q2 2025 delivered total operating revenues of $377M and Adjusted EBITDA of $106M, with Adjusted EBITDA margin excluding reimbursables improving to 29.4% from 22.8% in Q1; diluted loss per share was $(0.68) as a $51M legal accrual drove higher operating expenses.
• Versus S&P Global consensus, revenue modestly beat ($377M vs $363.0M*), Adjusted EBITDA was slightly below ($106M vs $109.4M*), and EPS missed materially (reported $(0.68) vs $0.632*), implying near-term estimate resets on profitability despite stronger activity conversion and utilization.
• Full-year 2025 guidance maintained for Adjusted EBITDA ($320–$380M) and capex ($250–$300M), with operating revenue range raised to $1.32–$1.38B (excl. $50M reimbursables), supported by contract awards for West Vela (Talos) and Sevan Louisiana (Murphy).
• Management emphasized disciplined contracting, improving utilization (93% vs 84% in Q1) and backlog of ~$2.5B as of Aug 6, while framing 2025 as a trough ahead of recovery in late 2026–2027; catalysts include Brazil tenders, Angola JV fixtures, and well-intervention opportunities that minimize idle gaps.

What Went Well and What Went Wrong

What Went Well

• Economic utilization improved to 93.4% (from 83.9% in Q1) and average contractual dayrates increased to $331K/day, driving higher contract revenues and Adjusted EBITDA.
• New contracts converted: West Vela secured ~90 days with Talos starting mid-November; Sevan Louisiana began a three-well intervention campaign with Murphy in August, expanding customer base and bridging near-term gaps.
• CEO highlighted operational excellence and technology investments (West Minerva real-time ops center, Seadrill Academy MPD training), reinforcing differentiation and client satisfaction: “our unwavering commitment to operational excellence… enables us to deliver best-in-class service”.

What Went Wrong

• A $51M unfavorable legal judgment (Sonadrill fees claim) raised management contract expenses, contributing to a net loss of $42M and diluted LPS of $(0.68) despite stronger topline.
• Working capital headwinds (receivables build, settlement of prior project costs) limited operating cash flow to $11M and resulted in negative Free Cash Flow of $(12)M in Q2.
• Near-term U.S. Gulf market remains competitive with temporary oversupply and softer utilization, pressuring dayrates; management expects a recovery into 2026–2027 but notes operators’ caution amid macro volatility and tariffs uncertainty.

Transcript

Speaker 6

My name is Gil, and I will be your conference operator today. At this time, I would like to welcome everyone to the Seadrill 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 that time, simply press star followed by the number one on your telephone keypad. If you would like to repeat your question, kindly press star one again. It is now my pleasure to turn today's call over to Mr. Kevin Smith, Vice President of Corporate Finance and Investor Relations. Please go ahead.

Speaker 5

Welcome to Seadrill's second quarter 2025 earnings call. I'm Kevin Smith, Vice President of Corporate Finance and Investor Relations, and I'm joined today by Simon Johnson, President and Chief Executive Officer, Samir Ali, Executive Vice President and Chief Commercial Officer, and Grant Creed, Executive Vice President and Chief Financial Officer. Our call will include forward-looking statements that involve risks and uncertainty. Actual results may differ materially. No one should assume these forward-looking statements remain valid later in the quarter or year, and we assume no obligation to update them except as required by securities law. Our filings with the U.S. Securities Exchange Commission provide a more detailed discussion of our forward-looking statements and the risk factors affecting our business. During the call, we will also reference non-GAAP measures. Our earnings release, furnished to the SEC and available on our website, includes reconciliations with the nearest corresponding GAAP measures.

Our use of the term EBITDA on today's call corresponds with the term adjusted EBITDA as defined in our earnings release. I'll now turn the call over to Simon.

Speaker 1

Hello, and thank you for joining us on our call. Today, I'll touch on our quarterly performance before moving to contracting updates, some company updates, and the market. Samir will then discuss our commercial outlook in detail, and Grant will review our quarterly financial results and full-year guidance. In the second quarter, Seadrill delivered an adjusted EBITDA of $106 million and an adjusted EBITDA margin excluding reimbursables of 29%. Two of the active customer dialogues discussed on the previous earnings call have been successfully converted into new contracts. These fixtures underscore the strength of our commercial team in a competitive environment. The West Valley was awarded a two-well contract with Talis Energy beginning mid-November with an estimated term of 90 days, and the Savannah-Louisiana commenced a well intervention contract with Murphy Oil in early August and is expected to work into November.

This will be our first campaign for Murphy, and we are thankful that they have entrusted the work to us. Importantly, these fixtures commence in the second half of 2025, thereby minimizing costly gaps between contracts. Discussions around the three rigs in our Sona Drill joint venture in Angola, the Sonangol Libongos, Sonangol Quenguela, and West Gemini, remain very positive, and we expect material progress on contract fixtures in the near future. In all areas where we operate, our unwavering commitment to operational excellence is what enables us to deliver best-in-class service to our valued customers, resulting in long-term partnerships. The second quarter of 2025 marked an extraordinary 15 years of operation for the West Gemini in Angola, during which the rig worked primarily for TotalEnergies.

Throughout this time, we have consistently set the standard by delivering sustained operational and safety performance, achieving 97% uptime and a TRIR of 0.13 over the last decade. TotalEnergies remains a critically important customer, and we thank them for their long contractual commitment to the rig. Driven by our commitment to leading-edge innovation and continuous improvement, Seadrill has established the West Manöver real-time operations center at our office in Houston. This cutting-edge facility utilizes advanced analytics and real-time data integration to enhance situational awareness, improve decision-making, and streamline communication across our offshore drilling operations. The positive feedback received from clients who have toured the West Manöver reinforces its significant value proposition. Complementing the capabilities of the West Manöver, our Seadrill Academy plays a pivotal role in strengthening Seadrill's performance through world-class training and development.

As part of the Seadrill Academy, the West Inspiration, our DrillSim 6000 simulator provides immersive scenario-based training in drilling and well control. Within the Seadrill Academy, we've successfully developed and implemented a comprehensive managed pressure drilling training course. Drawing our experience from drilling over 100 MPD wells, this in-house program is specifically designed to provide crews assigned to our eight MPD-equipped drillships with the knowledge and hands-on skills to continue to set the standard in MPD. This commitment to training and development is a cornerstone of the Seadrill culture. Together, the West Manöver and Seadrill Academy reflect Seadrill's integrated approach to technology, training, and performance, a winning model of continuous improvement that both we and our clients are proud of and believe in. Shifting to the broader market outlook, we view the current environment as fleeting.

Five key themes point towards a market recovery in late 2026, as widely commented on by us and our peers. Firstly, customers are focusing on exploration. At a recent conference, TotalEnergies reiterated its commitment to drill 15 to 20 exploration wells per year going forward. Meanwhile, BP confirmed increased investment in exploration with a plan to drill 40 wells over the next three years as part of a renewed focus on its core upstream business. This week, an exploration well in the Boomerang Block in Brazil's Santos Basin revealed BP's largest hydrocarbon discovery in 25 years. This significant find will trigger appraisal activities and underscores the potential within legacy basins. Brazil's fifth licensing round held in June highlighted a growing interest in frontier exploration and a significant re-engagement of the super majors.

Notably, 19 of the 34 blocks awarded were situated on the underexplored Equatorial Margin Play, where Exxon and Petrobras have jointly acquired 10 blocks. Chevron, in partnership with CNPC, secured nine blocks, signaling Chevron's re-entry into Brazil after an 11-year absence. The US Gulf of Mexico is set for increased exploration activity, with the Bureau of Ocean Energy Management holding lease sale 262 later this year, the first since December 2023. Recent legislation mandates at least two sales annually from 2026 through 2039, an increase from the prior mandate which only required three sales over five years. This expansion is expected to drive more exploration drilling and increased rig demand. Secondly, despite commodity price uncertainty, operators are moving forward with offshore project FIDs. Wood Mackenzie forecasts a substantial increase in FIDs from $91 billion in 2025 to $164 billion in 2026 and $133 billion in 2027.

These figures represent the highest levels in over a decade and underpin our belief in a market recovery. Thirdly, we're encouraged by recent tendering activity and the opportunities we see developing in coming months, which Samir will cover in more detail. Fourthly, there have been seven multi-year deepwater rig contracts awarded since March, with start dates in the second half of 2026 or 2027. These contracts demonstrate customers' long-term commitment to deepwater, even in an uncertain macro environment. Finally, recent transactions leave only one competitive ultra-deepwater drillship undelivered in the shipyard. Active drillship supply currently sits at 77 rigs, with contracting of just six units needed to reach 95% utilization. The stranded assets have been sold or delivered, and most of the cold-stacked drillships cannot be economically reactivated by a rational contractor. With that, I'll turn the call over to Samir.

Speaker 7

Thanks, Simon. As anticipated, 2025 is shaping up to be a year marked by softer utilization and a corresponding increase in competition, placing downward pressure on the near-term day rates. Despite the challenging backdrop, we have executed two new contracts. The Savannah-Louisiana has secured work in the U.S. Gulf with Murphy Oil, which will generate earnings and cash flow into November 2025. The rig's unique abilities to operate in shallow water environments in dynamic positioning mode open up a broader spectrum of work opportunities with new operators. Staying in the U.S. Gulf, the West Valley has secured approximately 90 days of additional work with Talis Energy, commencing in November, with a break of around one month following the end of the current program.

The rig continues to exceed expectations, enabling us to add term at strong rates at a time when many of our peers are experiencing increased idle periods in the U.S. Gulf. We are aggressively pursuing opportunities to fill our order book for the remainder of 2025, while also focusing on securing contracts for work with a 2026 and 2027 commencement date. As Simon mentioned, we are beginning to see evidence to support our view that an increase in activity is likely and frankly necessary to support energy demand through the rest of the decade and beyond. Paradoxically, market conditions are objectively better and subjectively worse.

The current trend of declining utilization exists in the same environment where we have a tightening of supply of rigs and the need for significant oil and gas investment to meet growing energy demand. Wood Mackenzie is forecasting a step change in customer spending from land to sea in 2026, where offshore CapEx will exceed onshore CapEx for the first time in a decade. The economics of offshore exploration are increasingly attractive, and we anticipate an inflow of capital into this market. When compared to 2025, deepwater spending is expected to increase over 80% and over 130% in 2026 and 2027, respectively. If realized, this level of investment would extend the durability of the cycle and help address any temporary dislocations between rig supply and demand. Our analysis indicates that drillship utilization will demonstrably improve in late 2026 and 2027.

Positioning our high-specification floater fleet at the heart of the deepwater market allows us to capitalize as spending is redirected towards offshore basins. In Brazil, which hosts the largest concentration of deepwater rigs, we anticipate demand to remain robust. The recent FID of the Gato de Mato project, Equinor's RFI for an additional rig on the Bacalhau field, and Petrobras's Maro and Búzios tenders give us confidence Brazil will remain the key deepwater destination for some time. This is complemented by a notable uptick in interest by the super majors. During the recent offshore bid round, over $180 million in signing bonuses were paid. For context, this is more than double compared to the last round held in 2023. Seadrill is a leading operator in Brazil with six drillships currently working in the country. Our strong track record, deep customer relationships, and local presence position us well.

Of our fleet, only the West Carina has near-term availability, and we are actively exploring opportunities both inside and outside Brazil for this unit. Here in the U.S. Gulf, we maintain our view that around four to five rigs are expected to be marketed and available at year-end, creating a temporary oversupply. Despite these headwinds, we have secured near-term work for the West Valley, which is a testament to the exceptional operational performance delivered by our crews. We anticipate demand will improve in 2026 and again in 2027, with idle rigs being reabsorbed and stronger utilization supporting rate progression. Regarding our fleet, we are in active dialogue with multiple customers for work with a 2026 start date for the West Valley and West Neptune.

To finish our overview of the Golden Triangle, West Africa remains a significant source of incremental growth, with at least six long-term drillship opportunities targeting 2026 and 2027 commencement dates. Securing term work for rigs in Angola remains a key strategic priority for the Sona Drill joint venture, as we look to enhance the longevity of the partnership. Discussions for all three rigs remain constructive, and we look forward to providing an update in due course. Outside of the Golden Triangle, Norway remains a region in balance, while East Africa and Asia-Pacific are showing tangible signs of incremental demand. We are currently tracking opportunities that could absorb over 22 years of drillship demand, with programs commencing in 2026 and 2027.

The West Capella is engaged in a competitive tender process for term work in Asia, and we are tracking at least 13 active programs across Mozambique, Australia, and Southeast Asia with startups in the next two to three years. In summary, we see the potential for strong market recovery in late 2026 and 2027. While the precise timing of customer demand remains uncertain, the underlying need for exploration and reserve replacement is clear. Our fleet is underpinned by a solid foundation of backlog extending into 2028, and as market fundamentals improve, we remain confident in our ability to maximize earnings and cash flow for each rig. With that, I'll hand it over to Grant.

Speaker 4

Thanks, Samir. I'll now walk through our second quarter financial results before providing an update on our full-year 2025 guidance. Total operating revenues for the second quarter were $377 million, representing a sequential increase of $42 million. This improvement was driven almost entirely by higher contract drilling revenues. Both the West Neptune and West Polaris benefited from sequential increases in operating days, as the Neptune completed its scheduled SVSN upgrade, while the Polaris commenced its contract with Petrobras in mid-February. These items were partially offset by reduced operating days for the West Capella, which completed its contract in the prior quarter. In addition, economic utilization improved to 93%, up from 84% in the first quarter.

The marked increase in revenue conversion was driven by the West Arriga and West Polaris, which resolved teething issues following the commencement of their inaugural long-term drilling contracts in Brazil, as well as the West Tellus, which resumed operations in February. Finally, management contract revenues increased $4 million quarter on quarter to $65 million, reflecting an agreed-upon inflationary increase for the daily management fee Seadrill earns for providing management, operational, and technical support to Sona Drill. The increase was retroactively applied from January 1, 2025. Turning to expenses, total operating expenses for the second quarter were $371 million, up from $317 million in the prior quarter. This increase was driven primarily by a $51 million accrual recorded in management contract expenses related to an unfavorable legal judgment associated with the establishment of the Sona Drill joint venture dating back to 2018.

As previously disclosed, approximately $10 million of the total liability pertains to 2025 and impacts current year adjusted EBITDA, and the remainder relates to prior periods. Adjusted EBITDA was $106 million, up $33 million from the prior quarter, and adjusted EBITDA margin excluding reimbursables was 29.5%. Moving to the balance sheet and cash flow statement, we continue to maintain a robust balance sheet with ample liquidity and the lowest net leverage in our peer group. At the end of the second quarter, gross principal debt remains $625 million, with maturities extending through 2030. We held $419 million in cash, which included $26 million of restricted cash.

Net cash flow from operations during the second quarter was $11 million and includes unfavorable working capital movements of $66 million, driven by an increase in trade receivables for the West Neptune, West Tellus, and West Polaris, as well as settlements of project costs incurred in prior periods related to the West Arriga and West Polaris contract preparations and the West Neptune special periodic survey and upgrades. Payments for capital additions captured within investing activities were $23 million. Now, moving on to our full-year outlook, we maintain the adjusted EBITDA range of $320 million to $380 million, and that's based on an updated range for operating revenues of $1.32 to $1.38 billion, which excludes $50 million of reimbursable revenues. Adjusted EBITDA guidance includes a non-cash net expense of $33 million related to the amortization of mobilization costs and revenues, of which $14 million has been recognized through June 30.

Full-year capital expenditure guidance range is also maintained at $250 to $300 million. With that, I'll hand back to Simon for his closing remarks.

Speaker 1

In summary, we are pleased with the momentum we've built through recent contract awards. We remain actively engaged in constructive dialogues with customers for additional opportunities. As we look towards 2026, we're focused on maximizing profitability and minimizing gaps between contracts. With our backlog profile and disciplined approach to contracting, we remain well-positioned to deliver long-term shareholder value as the market improves. Through leading-edge innovations and our relentless pursuit of operational excellence, we will continue delivering safe, efficient, and reliable operations for our customers every day. With that, I'll now hand the call over to questions. Operator?

Speaker 6

At this time, I would like to remind everyone that in order to ask a question, please press star followed by the number one on your telephone keypad. We kindly ask to please limit your questions to one and one follow-up only so that everyone can have the chance to engage with our speakers for today. We will pause for just a moment. Lucy, your first question comes from the line of Fredrik Stene with Clarksons Securities. Your line is open.

Hey, Simon and team. Hope you are well and we're having a good morning so far.

Speaker 4

Morning, Frederick.

Morning, morning. I wanted to touch upon the contracting opportunities that you're mentioning, and maybe even more so in the written report. You did have the Bella and the Louisiana contract today, but I also got the impression that there is more in store in the relatively near future. Just looking at the fleet roll-off, I would be inclined to think that this potentially relates to the Sona Drill rigs, potentially relates to the ongoing Búzios tender, for example. Any more color you can give on that would be super helpful. Also, maybe some Búzios specifics. As an overarching question around this, based on the discussions that you're currently having, do you have a pipeline of potential work for all your rigs, that is non-stack rigs, going forward?

Speaker 7

Hey, Fredrik. There's, I guess, a few questions in there. I'll start with the Angola one. As some of you may be aware, there's been a bit of political unrest in Angola, which has candidly added some delays to the administrative process there and delayed approvals. We remain quite optimistic in our abilities to recontract our Angola fleet. We're in advanced dialogue on all three assets. For us, that is a market that we continue to believe we have a competitive position in and should be able to announce something hopefully in the near future. It takes some time. I'd also say, if you look at that market, you've seen some assets leave, which again gives us confidence that we are at the top of the pecking order there of getting new contracts. You had asked about Brazil a little bit.

I can't get into it specifically, but we've done a pretty good job of contracting our fleet in Brazil. We have six rigs down there. Of the six, we have the West Carina that's really the one with availability. I'd say we feel pretty good where we're positioned. You've got opportunities both with Petrobras, which are in the public domain, but you've also got some super majors that are also looking for assets in Brazil and outside of Brazil as well. For us, we are marketing the rig in multiple regions across the world. To close out, you had asked about our fleet that's not stacked. We have candidly active dialogue on all of those assets.

For us, we feel, as we said in the prepared remarks, and we continue to believe that the second half of 2026 and into 2027 is when we start seeing the recovery in the market. We think we're approaching the bottom, which could be later this year or early next year, and then we start recovering into 2026 and into 2027.

Speaker 1

Yeah, and just to add, Fredrik, to Samir's comments, I think that we're increasingly confident that the market's going to improve through 2026. You know, the work is starting to appear in tendering activity, and some of those long-dated FIDs that have been awarded of late. 2025 is a knife fight, but we've demonstrated our ability to win work that our peers haven't been able to put a glove on. We're quite pleased with the progress of our contracting, and we're just continuing to work diligently. The best advertisement that we have for us is the performance of our rigs, most notably the West Valley and the Savannah-Louisiana. Those rigs are winning these contracts by virtue of the performance that they provide every day to our client base. I'm ecstatic with what the guys on the rigs have been able to deliver to the clients.

Speaker 4

All right, that's super helpful. Just a super short follow-up to my one question. Is, are there any rigs for which we should expect prolonged idle time in between contracts?

Speaker 1

I think we're using every endeavor to ensure that we don't create our own white space. We do have a couple of small gaps that we spoke to with the Savannah-Louisiana in the near term. I think the marketing team has really taken up the baton in ensuring that we endeavor to keep the rigs working and that we build backlog that's in continuous, in direct continuation of existing contractual commitments. So far, I've been really pleased with what the guys have been able to deliver there. We'll see how it goes. It's a competitive environment, but it's an improving one. I'm really confident with what we've delivered and how things will pan out going forward. Anything to add, Samir?

Speaker 4

All right, thank you so much. Have a good day.

Speaker 1

Thanks, Fredrik. Thank you.

Speaker 6

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

Speaker 7

Hey, good morning. Thanks for taking my question.

Speaker 4

Morning, Dave.

Speaker 7

If I recall correctly, you previously didn't sound keen on putting in capital into idle assets without a strong line of sight for contracting. Samir, I appreciate your comments about being in advanced dialogue in the Angola market. I just wanted to make sure, thinking about the prior comments about not investing in the rigs, in idle rigs, is it fair to think that you probably wouldn't start the SPS for the West Gemini unless you had pretty strong visibility for future work?

Speaker 1

Yeah, that's correct, Dave. Generally speaking, we're reluctant to engage in work that is discretionary, ultimately, without a firm contract behind it. I think Samir gave a really good indication of where we're at with those rigs that are looking at work down in Angola. At the same time, we don't want to extend unnecessarily idle periods while we're waiting for final approvals. I think what we've done there with the West Gemini is we offloaded a lot of operator equipment in Angola before we moved to Namibia, and we've essentially been standing by. We have done a little bit of work, but it's not of a material quantum. We hope, as Samir said, to have some good news on the contracting front, and at the same time, we'll press the button on going full forward with the survey work and contract preparation that will be required for that work.

Speaker 7

I really appreciate that, caller. Just a little bit bigger picture one, if I may. In previous cycles, I think we've typically seen floater contract lead times kind of go in the same direction as utilization and backlog. In the past four or five months, we've seen operators locking in multi-year contracts with lead times of 12, 15, 24 months. Even though near-term demand looks soft and the rig count has been trending lower, it's creating some multi-quarter gaps in between contracts, which seems fairly uncommon versus prior cycles. One of the few reasons that I can think of for the change in operator behavior compared to prior cycles, maybe operators are seeing the same thing that contractors have been saying, right? The demand outlook in late 2026 and 2027 is strong. The market could be tight. Better to lock in the rigs they need now.

Maybe I'm missing a better explanation. I was curious for your thoughts.

Speaker 1

Dave, I'll let me start and then Samir can add some color. No, we see it the same way you do. We think that there's an improving dynamic. We're clearly in a bit of a trough at the moment. We've talked about how the market's, you know, developed and what unique features this business cycle, you know, versus previous. One of those has been the lack of visibility. Yeah, we believe fundamentally that those people who are going long and low now are doing so because they believe it'll confer an advantage with what's coming ahead. When we think about that and when we think about our exposure to the market, a lot of people are concerned about our ability to recontract. We're relatively calm in terms of what lies in front of us.

We see our near-term exposure to the market as evidence of operating leverage relative to our peers. Certainly, Samir and I have had a lot of high-minded conversations about the importance of not going long and low. I think some of these longer-term fixtures that have been brought to market recently, I think they were greeted by spectators and market participants with great interest and applause. We were certainly glad to see those rigs receive that work. It'll be interesting to see whether those fixtures stand the test of time, and whether they'll come to be seen as being such good fixtures in the future. Like I said, we believe now is not the time to go long and low.

Speaker 7

Dave, the only thing I'd add to that is, for us, we've been very, very focused on making sure we add to the white space that exists today in 2025 and into early 2026. Candidly, we're getting the rates our peers are getting for work that starts late 2026, early 2027, but we're getting it for near-term work. For us, minimizing those gaps between contracts is absolutely paramount. That's where we've been very focused on making sure that we have as much direct continuation work as we can get.

Speaker 1

That's great. Thank you very much. I'll turn it back.

Speaker 7

Thanks, Dave.

Speaker 6

Your next question comes from the line of Truls Olsen with Clarksons Securities. Your line is open.

Thank you. Hi, guys.

Speaker 1

Morning, Truls.

Morning. A couple of quick questions from me. This goes back to perhaps earlier calls. Sorry if you've already been through this, but my line broke you for a while. You spoke about the CJ17 market in Norway and ConocoPhillips in demand. How is that? Any color on updates on that front?

Not much to share with you, to be honest, Truls. We haven't heard anything more from Conoco. Discussions to date have indicated that the World Program will take the rig into late 2026. We recently received Rig of the Year from Conoco for the service delivered by the West Solara. We know the rig's performing well, but we're no further forward in terms of understanding what their long-term plans are for their jackup fleet in Norway.

Okay, understood. Another topic is the Fetch claim and that voluntary mediation which you have entered into. Any updates from the caller you can share on that one?

Yeah, sure. Look, we don't really have a material update since what we shared with the market on the first quarter earnings call. We continue to have constructive discussions with Petrobras, and we're preparing for the mediation process, as we previously disclosed, which is in its very early stages. Some of our peers who are part of the same process seem to be a little bit further forward than we are. We expect to have some feedback on the mediation in early July, but that hasn't been the case. It's not affecting our day-to-day operations or any future contracting opportunities for that matter. This is a really complex legal matter that relates to a project that dates back over a decade.

Given that it's in Brazil and it's part of a much larger dispute between SESHA and Petrobras, we expect it to run for some time before we get a clear idea as to how it might be resolved. Importantly, it hasn't stopped us from bidding for additional work with Petrobras. I make specific sort of reference to the West Carina there. We're a strategic contractor for Petrobras. We've got five rigs under contract to them, and, as I say, an outstanding tender at present. We will do what we need to to preserve our company's interests. As I said, I think I've said to many people before, I'm not sleepless at night worrying about this issue. Unfortunately, we can't control the pace of resolution. It's going to take some time. We're encouraged that it was Petrobras who proposed the mediation process to the drilling contractors affected.

We just ask everyone to be patient as things develop, and we will keep people updated as and when anything material occurs.

Excellent. Thank you. Given the market outlook, hopefully you can start to sleep even better going forward as well on the other front. Anyways, the final element, you talk about near-term opportunities and being a competitive market, obviously with a, call it, positive movement. Anyways, day rates on the Savannah-Louisiana, any color you can give relative to, call it, recent market data points?

Speaker 7

Sure. I'd say with the Bella, my earlier comment was we're getting similar rates to what our peers are getting second half of 2026, early 2027. I'd say, again, we're getting it in 2025 to give you some context of where rates are landing. We're not taking any of the white space that others are willing to accept. For the Savannah-Louisiana, as Simon mentioned in his prepared remarks, that is intervention work that we're doing right now. Obviously, that does come at a different price point. For us, it's still cash flow positive and it's EBITDA positive. For us, it's still good work and we're happy to add it to the Savannah schedule.

Okay. Excellent. That's all for me. Thank you.

Thank you, Truls.

Speaker 6

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

Yeah, hey, thank you and good morning and thanks for taking my questions, everybody. Simon, I'd be kind of curious, right? Like kind of what's your view or outlook on the intervention market? Clearly, the Savannah-Louisiana has had some success. Well intervention is different than drilling, but it seems like a viable business, not only in the US Gulf of Mexico, but kind of broader based. We've seen opportunities for well intervention, obviously in the North Sea for years, West Africa, Brazil more recently. Just kind of curious how you're thinking about the well intervention market. Is really this just a one-off opportunity for the Savannah-Louisiana, or could this become something more important to Seadrill over time?

Speaker 1

Yeah, look, I think for us, Greg, it's really principally related to achieving continuous utilization on the Savannah-Louisiana schedule. We have been looking at some deeper relationships with providers of critical equipment that allows us to perform that kind of work in, shall we say, an optimal manner that's equivalent to what you see with a more vertically integrated well intervention specialist. That's been interesting. No, really, it's about ensuring that the Savannah-Louisiana, which is, you know, it's got some unique capabilities in terms of its dynamic positioning ability in shallow water. Also, there's a small but really important client base in that transition zone in the US Gulf of Mexico who need to flip between well intervention and conventional drilling work.

We're looking at how we can facilitate that with that particular rig, as I say, based on its special water depth capability, but also on its ability to switch between modes of operation. I think speaking more generally about the well intervention market, what you say is quite true that it's sort of expanded from what really has been a conversation around plug and abandonment liabilities and mature legacy basins like the North Sea. We're now seeing that there's a much greater appetite for both P&A, but also, shall we say, enhanced well intervention in some of the maturing reservoirs in Southern Africa, in Brazil, and certainly in the US Gulf of Mexico. There's a relatively small number of vessels worldwide that perform that work. I think the operators are telling us that they're increasingly frustrated with the high cost of mobilizing units between those quite sort of distant geographies.

What we're trying to do is to provide an in-basin solution that, whilst it potentially is lower value work than ordinary drilling work, it does allow us to provide visibility on the Savannah-Louisiana schedule. It fills a much-needed gap that the operators have been worried about for some time.

Yeah, no, 100%. I did have another question. I don't know how much you can talk to it about, but kind of curious. On those options on the Vela, typically when we see longer-term work, at least the options tend to be a high price. Any kind of color you can give around those options, those customer options on the Vela, and yeah, are those at a higher level than the rig is going to work at in November?

Speaker 7

Greg, we can't go into the exact rate, but I'll tell you your guess is pretty good.

Okay. Yeah, no, that's—I wasn't looking for a rate. I was looking to understand if, you know, sometimes in previous cycles we've seen options being flat and other times we've seen them higher. Maybe they're lower sometimes, but no one really knows. Just one other question I had. You know, some of your competitors, you know, it's actually been impressive how they've looked at maybe some of their non-core assets and just retired them. Realizing that, you know, your fleet, you have some rigs that haven't worked in years, you know, some rigs that have worked more recently. Any kind of outlook on maybe some of the more longer-term stacked rigs in the fleet and the potential we could see those kind of head off to the scrap yards?

Speaker 1

Yeah, happy to talk about that, Greg. I mean, there are three rigs in particular with us that fall in that category. There is the West Eclipse, which has been cold stacked now for in excess of five years in Southern Africa. We, from time to time, look at opportunities to remove that rig from the supply and recycle it. We've also received a number of interesting options around repurposing that rig from parties who want to deploy it for non-drilling, non-oil field-related applications, in fact. The only reason that I think we haven't progressed with that particular rig has just been our interest in this business development opportunity. In terms of the Aquarius and Phoenix, which are stacked in Norway, we don't see any material activity improvement at Norway until mid-2026 at the earliest.

Both rigs require a material capital allocation to put them back to work, both five-year SPS work and also equipment upgrades to continue to work in Norway. I want to make it quite clear that those rigs have a lot of life left in them. We have a history of monetizing rigs at premium value. To the extent someone were to show interest in buying those rigs from us or with us a trade sale opportunity, that's something we would definitely look at on the merits at the time. It's important also to remember that harsh environment assets are much more expensive to replace than benign environment deepwater units, especially those with the ability to work in Norway. I don't think you can expect us doing anything on the recycling front with the Aquarius or the Phoenix anytime soon.

They have life in Norway, we believe, albeit not in the immediate future. Certainly, they have opportunities in harsh environment markets outside of Norway.

Okay, super helpful. Thank you very much.

Thank you, Greg.

Speaker 6

Your next question comes from the line of Hamid Karsand with BWS Financial. Your line is open.

Good morning. My first question here is that your commentary is now changing to end of 2026 for the market. I just wanted to understand what your expectations are for day rates, given that there's more and more availability as you go into 2026 for these contract opportunities.

Speaker 7

Yeah, it's still a competitive environment out there, but day rates are still holding up pretty well. I'd say a year ago, we were looking at five handles in late 2026. Is that possible? Obviously, it's still there, but I'd say we're probably slightly lower than that. Rates are still holding up for the most part, especially in the US Gulf of Mexico.

Okay, great. Thank you.

Speaker 1

Thanks, Hamid.

Speaker 6

Your next question comes from the line of Josh Jayne with Daniel Energy Partners. Your line is open.

Thanks. Good morning. Thanks for taking my questions. Apologies if this was covered in the opening remarks, but could you remind me how many of your drillships have MPD, how you are thinking about additions moving forward, and maybe just give you the floor to talk about MPD as a competitive advantage as it relates to your fleet today?

Speaker 1

Yeah, you bet, Josh. Let me start off and then Samir can fill in the gaps. Eight of our drillships are equipped with MPD. We also have a jackup that's operated utilizing both MPD and Control Mudline technology. MPD and the semi in Norway have also deployed the Control Mudline technology. We think that we're a thought leader in this space. We've drilled in excess of 100 MPD wells across the company now, and we're one of the few drilling contractors that's utilized every single one of the technologies that's out there today. In the past year or so, we've been working in close collaboration with Oil States Industry to deliver to the industry a new improved IRJ.

Both through our collaboration with Oil States and certain other sub-vendors, we've been able to effect major improvements in rig up, rig down times, and also the durability of the bearings that support the rotating packing elements. I think MPD is in the process of making that transition from what has been a conventional rental solution delivered by a service company to something that's becoming more integrated into everyday rig operations. That's certainly been our approach. We operate the equipment as if it were ours, even if it's provided through a third-party vendor. As I say, we've been working closely with those same vendors to improve outcomes. We've got a huge amount of interest on the unit that we've deployed down in Brazil with the West Polaris, and we'll be doing an operator demonstration day in conjunction with Oil States here in the next month or so.

I'm really happy with the work that we've done. We see this as an important part of what we do, and it's a differentiator relative to some of the other drilling contractors who haven't put as much effort into it as we can. Samir, anything to add?

Speaker 7

I'd say commercially, it's becoming more and more important. You know, in the U.S. Gulf, it's almost becoming a must-have. Both of our assets in the U.S. Gulf, or both of the drillships in the U.S. Gulf, are equipped with it. I'd say in Brazil, it's starting to become more of a requirement. West Africa is probably, of the Golden Triangle, probably the third of needing or requiring it. As we talk to more and more operators, it is becoming, from a nice-to-have to almost a must-have. I wouldn't be surprised if, in five years from now, it's required pretty much everywhere.

Speaker 1

Yeah, I think just one final thought too is that it's often in the past been utilized for a given whole section or for a specific technical challenge. Increasingly, people are starting to look at it in the light of how it might be used as a performance tool. I would not be surprised if five years from now that wells are drilled with a closed system from nickeling up of the wellhead until completion of the well. That hasn't been something that people have envisaged until in the last year or two. We're excited about the future of the technology. We think it's inherently safer than conventional operations. Yeah, we're leaning into this.

Thanks for that. As my follow-up, I just wanted to talk through what signs you're ultimately looking for to begin buying back shares again in the market. I think it's pretty well understood across the industry, sort of, you know, the market is softish from now until the first half of 2026, but then everyone's expecting a pickup at that point. What signs are you ultimately looking for before you progress again with the buyback and just how you're thinking about it systematically would be great. I'll turn it back. Thanks.

Yeah, absolutely. We have a financial policy in place that talks about our ambitions and what our parameters are for return of capital. Of course, as 2027 comes into the frame and what we anticipate in terms of the cash flow that our operation will deliver, obviously, shareholder returns is at the top of the list of the matters that our board's bending their mind to. We're definitely encouraged by the way that the market's developed, but we still remain concerned about some of the macro headwinds that we've all seen this last three to six month period. I think we're looking really for a bit of certainty and stability around things such as the tariff in terms of tariffs and understanding what impact they might have on our business. I think we'll sort of have a close look at what comes out of the bottom of our EBITDA machine.

Right now, as we signaled last quarter, our mind's focused on cash conservation. That could change going forward. It's a bit of a watching breeze, but we certainly need to see some stability in the general economy and a good oil price outlook, I think, before you see us get very active. Anything to add, Grant?

Speaker 4

The only thing I'd add is, you know, a big part of our story on cash flow generation is the repricing from our legacy Brazilian contracts. We've got three rigs there on contracts that were signed some time ago at the bottom of the market: Jupiter, Tellus, Carina. We've now recontracted two of those at substantially higher day rates. That uplift will kick in from the second quarter of next year, and that uplift will flow directly to the bottom line and ultimately cash. Of course, Samir has talked about the third of those, Carina. We're actively pursuing opportunities in Brazil. That'll be a big, you know, key milestone in our cash flow generation story that'll be important to capital returns, Josh.

Understood. Thanks. I'll turn it back.

Speaker 6

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

Hi, good morning.

Speaker 1

Hello, no.

I just had a couple. I was wondering, as you talk with different operators, is the sort of capital discipline-driven risk-reward thinking among the customers pretty uniform across customers? Are there differences between regions or between the national oil companies and what the majors and the independents are thinking? Just wondering if you have people coming at you with totally different scenarios in mind or if it's pretty uniform.

Speaker 7

It's relatively uniform. I'd say the bigger the company, the more pressure there is on capital return and giving capital back to shareholders. We do also operate for some private companies. The private companies have their own motivations. The outcome is still the same in either scenario, as you've seen just a deferral of demand. In the same breath that they're deferring demand, they will openly acknowledge that this can't happen forever. There is a tacit acknowledgement of, look, we're deferring it now, but we know we're going to have to come back to market and we're going to need that asset to drill wells in late 2026, early 2027. You're starting to see that already with some of these companies contracting for assets in 2026, 2027, and 2028.

Speaker 1

I think 2025 will prove to be a very grim low point when we're looking back in a couple of years' time. There's been a pronounced lack of exploration success year to date relative to historical run rate. We've seen a real low water point in terms of the number of FIDs that have progressed. I think the point that Samir makes really needs to be underlined that that's not sustainable given the world's need for cost-effective hydrocarbons. I think that you can't just continue to kick the can down the road. Certainly, we're starting to see activity levels now and forecasts around FIDs and project sanctions that are starting to underline that there's going to be a lot more drilling demand going forward.

Right. Thanks. You mentioned disappointments on the exploration front. We had a nice exception with BTIG's discovery at the Boomerang offshore Brazil. Given the size of that, is that enough, you think, to sort of help affirm or accelerate exploratory interest in the industry?

I think that's a good start, but I think on a worldwide basis, it's a drop in the ocean in terms of what's needed. It's certainly great that it's BP has had that success because, I mean, they've recently changed their strategy and redirected their efforts back towards conventional hydrocarbons away from renewables. We're pleased with that. I think the most important thing is, as we said in the prepared comments, we believe it's going to drive some near-term activity in Brazil around appraisal drilling. We don't know too much on exactly the size of the wells' reserves. It's probably a bit early to make any accurate determination of that, but the aerial extent of the reservoir is enormous.

That, coupled with the amount of pay that we understand was in the zone that they penetrated, that's a really good news story for BP and a good news story for a part of the Santos Basin that a lot of people have written off as played out. I think we made the point that some of these legacy reservoirs still have a lot of energy left in them. It's great that BP had this success.

Great. Thanks. Thanks for the call. Bye-bye.

Thanks, Nol.

Speaker 6

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect. Have a nice day ahead, everyone.