Subsea 7 S.A. (SUBC) Earnings Call Transcript & Summary

Good day, and thank you for standing by. Welcome to the Subsea 7 Q1 2025 Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Katherine Tonks. Please go ahead.

Welcome, everyone, and thank you for joining us. With me on the call today are John Evans, our CEO; Mark Foley, our CFO; and Stuart Fitzgerald, CEO of Seaway 7. The results press release is available to download on our website, along with the slides that we'll use during today's call. Please note that some of the information discussed on the call today will be included forward-looking statements that reflect our current views. These statements involve risks and uncertainties that may cause actual results or trends to differ materially from our forecast. For more information, please refer to the risk factors discussed in Subsea 7's annual report or in today's quarterly press release. The call today will be focused on our results, and we ask that you limit your questions to this topic. Securities laws in the U.S. and in other jurisdictions restrict us from discussing the proposed merger with Saipem. I'll now turn the call over to John.

Katherine, thank you, and good afternoon, everyone. I will start with a summary of the first quarter before passing over to Mark for more details on the financial results. Turning to Slide 3. Subsea 7 delivered a first quarter adjusted EBITDA of $236 million, representing 46% growth year-on-year and a margin of 15%. We reported a good operational and financial performance in both Subsea and Conventional and Renewables, and we're on track to meet our full year guidance, which is unchanged. Despite the uncertainties of the macroeconomic environment, Subsea 7 is experiencing continued momentum across the group and a positive tone to the discussions with clients. Slide 4 shows the growth in the backlog for both Subsea and Conventional and Renewables, which continue to increase in quality. We have a combined backlog for execution in the remainder of 2025 of $4.8 billion, giving us over 80% visibility for the year. And now I'll pass over to Mark to run through the financial results.

Thank you, John, and good afternoon, everyone. I'll start with a look at group and business unit performance in the first quarter before turning to the cash flow and financial guidance for 2025. Slide 5 summarizes the group's results. In the first quarter, revenue was $1.5 billion, up 10% compared to the same quarter last year, driven by strong performances in both business units. Adjusted EBITDA of $236 million, was up $74 million or 46% compared with the prior year, and our margin expanded by 380 basis points to 15%. After depreciation and amortization of $160 million, other gains and losses of $28 million, driven by noncash embedded derivatives as well as net finance costs of $17 million and taxation of $16 million, net income was $17 million. I will discuss the business unit performance in the next few slides. Slide 6 presents the key metrics for Subsea and Conventional. Revenue in the first quarter was $1.3 billion, up 6% year-on-year as good progress was made on projects in Brazil, Turkey, Angola and Saudi Arabia with Marjan 2 for Aramco nearing completion. Adjusted EBITDA was $225 million, equating to a margin of 18%, an increase of 440 basis points from the prior year. The margin in the quarter benefited from some specific one-off improvements in project profitability as well as the general continued mix shift towards projects with an improved balance of risk and reward. Subsea and Conventional benefited from a $7 million net income contribution from OneSubsea, in line with our expectations. Net operating income was $99 million, more than double the $47 million reported in the prior year period. Select Renewables performance metrics are shown in Slide 7. Revenue in the first quarter was $245 million, up 37% year-on-year, reflecting a good level of activity in Taiwan as well as early works on East Anglia THREE project in the U.K. Adjusted EBITDA was $25 million, equating to a margin of 10%, up from 1% in Q1 2024. Similar to Subsea Conventional, the renewables margin in the quarter benefited from some specific one-off improvements in project profitability. Net operating loss was $5 million, an improvement compared to a loss of $24 million in the same quarter last year. Slide 8 shows the cash bridge for the first quarter. Net cash generated from operating activities was $51 million, which included a $163 million build in working capital. Such movements have been characteristic of the first quarter for the last couple of years and as in prior years, are expected to reverse over the course of the year. Capital expenditure was $76 million, including the installation of a monopile gripper on Seaway Ventus ahead of its activities at East Anglia THREE. Net cash used in financing activities was $106 million, which included lease liability payments of $59 million and a repayment of borrowings of $31 million. At the end of the quarter, cash and cash equivalents decreased by $116 million to $459 million. Net debt was $632 million, including lease liabilities of $400 million, equating to a net debt to last 12 months adjusted EBITDA of 0.5x. The group had liquidity of $1.2 billion at period end, which included approximately $760 million of committed unutilized borrowing facilities. To conclude the financials, we turn to Slide 9. There is no change to our guidance for the full year 2025. As announced in February, we intend to pay approximately $350 million in dividends to shareholders this year. The first of 2 equal dividend payments of NOK 6.5 per share will be made on the 22nd of May. I will now pass you back to John.

Thank you, Mark. On Slide 10, we take a look at our alliance with BP. Subsea 7 and BP have worked together on oil and gas projects since the dawn of the industry in the U.K. North Sea. Over the years, as the industry has evolved, Subsea 7's role has expanded from pure T&I to full EPCI and later on combining our SURF solutions with SPS of OneSubsea through the Subsea Integration Alliance. Throughout the decades, we have worked closely together to deliver projects efficiently and safely. And this successful track record underpins a new phase in our relationship with the formation of the BP Alliance. The alliance allows us to work with BP at a portfolio level. With a more holistic longer-term view, we ensure BP has access to solutions, technology and resources it needs to fast track developments and optimize its return on investments. We have a range projects ongoing for BP listed here, some of which predate the alliance. They range from Europe to North Africa and the Americas, reflecting the global relationship. Most recently, we announced the award of our third consecutive SIA project, called Ginger in Trinidad and Tobago, which followed on from [indiscernible] and the Cypre projects, and we are looking forward to extending our collaboration with BP in this region. Now on to a review of our tendering pipeline on Slide 11 and 12. Our Subsea client base investment decisions on long-term planning assumptions, and therefore, our tender pipeline is, to a significant extent, sheltered from short-term volatility in spot price. Furthermore, our focus on long-duration projects in cost advantaged sectors of the deepwater adds resilience to our subsea strategy. This means that whilst we've seen the price of Brent weaken in 2025, it remains well above the breakeven for our portfolio of potential projects. In addition, we have opportunities relating to strategic gas developments such as the Sakarya field in Turkey and to important new frontiers such as oil provinces in Namibia. Overall, while there has been volatility in the global economy, fundamentals of the Subsea industry remain robust. And today, Subsea 7 continues to experience high levels of tendering activity in Subsea. On the next slide, we have our wind prospects. As we have previously noted, our exposure to the U.S. wind industry has been very low, and we remain focused on the European and Taiwan markets. At Wind Europe in Copenhagen this month, there was a buzz amongst the developers regarding the up-and-coming CFD allocation round in the U.K. The industry is expecting bidding rules to be announced in May, the budget set by governments in June, a September auction and finally, results in November. Current expectations are for an allocation equivalent to around 10 gigawatts of capacity this year, up from 5.3 gigawatts last year and 0 the year before. Many of the projects on our U.K. list here will be included in this round, and Subsea 7 is well placed to secure a fair share of this work. To conclude, we turn to our final slide on Page 13. Subsea 7 finished the first quarter of 2025 with a strong backlog of firm orders valued at $10.8 billion. This gives us over 80% visibility on revenue in the remainder of 2025 and underpins high utilization of our global enablers. Our guidance for 2025 is unchanged, and we're on track to meet our expectations. We have a solid pipeline of tendering prospects, including those in cost advantaged deepwater markets, the gas markets and in the U.K. offshore wind. While we are, of course, cognizant of the prevailing macroeconomic uncertainties, reflecting the fundamentals of our business today, we are confident in the long-term outlook for the group. And with that, we'll be happy to take your questions.

[Operator Instructions] And your first question comes from the line of Sebastian Erskine from Redburn Atlantic.

Look a very robust set of results here. I'd like to start just on the tendering pipeline. There's a good mix in there on the slide in terms of the brownfield work and then also kind of discrete greenfield deepwater development. To your point, I mean, in this environment, do you see the shorter cycle infill drilling, the subsea tiebacks being paid back as opposed to those larger projects, where a lot of engineering resources already been allocated or the opposite? I guess your expertise would be useful here just to get a sense -- of that sensitivity? And then secondly, just on the SIA and the work that you're securing there. I mean your North American listed peer talks a lot about the differentiation they offer via kind of integrated SPS, SURF, EPCI. So it's a helpful reminder that you to offer these services. I guess a bit more on the value of the alliance and the contribution it's had to your backlog P&L and maybe specifically some of the future projects in your pipeline that will be serviced and tendered via the SIA.

Thank you, Sebastian. As I said in the prepared remarks, we're not really seeing any fundamental change in our dialogues with our clients. So we have the mix, as you pointed out, between brownfield step-outs and greenfield opportunities. So Namibia is greenfield. We're seeing opportunities of further expansions out on greenfield potentials in Turkey and such like as well as the usual opportunity sets in brownfield. Petrobras continue to push ahead. You'll see on this slide that Atapu 2 and Sépia 2 are on the list, which are currently being bid. And we expect to see Buzios 12, another big greenfield project coming into bid before the end of the year. So at the moment, we're not seeing a change. We always had that mix in our tendering pipeline, and we'll always have that mix of brownfield and greenfield in our projects, as we move ahead. Moving to the Subsea Integration Alliance. We've had that in place since 2015, and that has been a very successful relationship between ourselves and SLB, OneSubsea. And the announcement yesterday of Ginger for BP is again an example of how clients see the value of the SIA. We see Equinor using that as they look to get their existing Bay du Nord projects through to sanction. And that's about a lot of early engagement and putting our technologies on the table. So we feel very, very comfortable that we work very well in that part of the world, in that sector of the industry. And we have a number of significant clients who enjoy working with us in that model. So again, for us, it's an important part of our capability, but we've always been very flexible to work with our clients in whichever contracting format they want, if they want transport and install, if they want EPCI, they want integrated SURF and SPS, we will do all of those different contracting models. So again, Ginger is another example. We went into Trinidad for the first time with BP 3 years ago. And now we've just been awarded our third continuous project there in Trinidad, and there's more opportunities there. We see this being repeated in many different countries around the globe with our clients. So that, in a nutshell, is the SIA.

Your next question comes from the line of Guilherme Levy from Morgan Stanley.

I have 2, please. The first one, it's been a while since we heard about Buzios 11. So can you perhaps share any updates there in terms of the negotiations with Petrobras? And then the second one, just in terms of the global environment for tariffs. I know that your direct exposure to the U.S. is minimal. But are there any particular raw materials or equipment that you source from the U.S., for which you could be exposed in case of a higher cost. I'm not sure if all your contracts protect you against changes in tax laws. So yes, any color there would be great.

Thank you. I won't comment specifically on Buzios 11. It's been in the press. It's -- that information is public in Brazil. Petrobras go through a process of reviews and partner agreements and such like that are needed, and that process is well underway. So again, I would expect to see that process moving ahead. Thing to remember there is, again, we offered a very cost competitive offering on Buzios 11 in Brazil. And as we've discussed before, there is a portfolio of different projects available for bid. We're seeing a lot of interest in the market there. But as I said in my previous response to Sebastian, we're seeing Buzios 12 now, for example, being ready to go into the system. So as everybody knows, Petrobras have a system of managing their bidding process, and we're in the middle of that process at the moment. Turning to the tariffs. We have about $600 million worth of work in the U.S. So about 6% of our backlog is in that part of the world. And again, we have worked there for a shade under 40 years. So we're very established in the U.S. We touched on the wind sector earlier, which we have a very low exposure to. In oil and gas, we have continued to service our clients primarily on step-outs and brownfield support in that part of the world. You saw that we won work with Shell and Sparta recently. So for us, at the moment, we're qualifying our newer bids. We have protections for changes in laws in most of our bids in place and contracts in place. So for us, at the moment, it's about evaluating it, working together with our clients to make sure that we address the tariffs correctly, and we'll move ahead from there.

Your next question comes from the line of Richard Dawson from Berenberg.

Two, focused on wind, please. I mean we saw Empire Wind in the U.S. construction suspended on that project. Revolution Wind appears to be continuing as normal, but would there be any impact to Subsea 7 if this project was halted, just given that you've got activities ongoing on that project? And then secondly, on the prospect list for offshore wind, a fair few number of additions coming through. And I appreciate you don't give indicative contract sizes for those new awards. But is there anything you can say about how significant these new opportunities are, particularly in the U.K.

I'll suggest that Stuart takes these.

Yes. So thanks, Richard. So on the first question in relation to Revolution, we have -- we're about 70% of the way through that project with those offshore works complete in a campaign that we carried out last year. We have an additional campaign in 2025 in the second half of the year. I would say, less than $100 million of revenue to go. So some -- if that does not go ahead, then there will obviously be discussions with the client in terms of the cost coverage that we get for any commitments that have been made with a degree of protection in the contract there. So I would say at the margins in terms of any kind of potential impact from a Revolution cancellations. But as you mentioned, there are no indications at this stage that, that will happen and campaigns on other vessels with other contracts are commencing imminently. So that's the story on Revolution. In terms of the market, as we get close to the CFD applications, if you like, then we get more visibility as to the potential projects, which may be submitted into that round by different developers. So some of those are larger, some of those are smaller. I wouldn't, as you said, want to comment on the specifics of the different jobs, but we're just starting to get a bit more visibility of which developers are going to put their -- or may put their hat in the ring in the coming CFD round. I think as John says, the encouraging sign is that the volume, which means the number of projects which could be awarded CFD looks like it's going up materially compared to last year.

Great. And maybe just a quick follow-up on the wind space. Just in terms of competitors, I mean, obviously, different competitors operating in wind than in the Subsea and Conventional space. What does fair share of new awards mean for Seaway 7?

I guess, maintaining or growing our current activity levels and revenue. In the U.K., in particular, we're the market leader. Again, I wouldn't want to go into specific percentages, but our track record in that market is significant. Our relationships with some of the key developers there are strong. It's our #1 region at the moment in terms of turnover, and we'd expect that to continue going forward.

Your next question comes from the line of Lukas Daul from Arctic Securities.

You reported 15% EBITDA margin in the first quarter. And in order to reach the midpoint of your 2025 margin guidance, you need to sort of approach 20% for the remainder of the year. So I was wondering how should we think about the margin trajectory going forward? And what would be the main contributors to that margin expansion?

Thank you, Lukas. I think we'd expect to see a gradual expansion of that, as the year progresses quarter-on-quarter. As Mark indicated, we're bringing in higher value project profitability and those projects are cutting in this year, as some of the older projects with less margin are dropping away from the portfolio mix. We're pretty comfortable that we've got a clear path. We know what work we've got. We've got some call-offs, which we expect to get on the shorter-term IRM. We have visibility of those. So for us, as we said in our prepared remarks, we're comfortable with our guidance for the year, and we expect to see the margins gently go upwards. But again, you can work out the gap between guidance and what we've delivered in the first quarter and model. That way, it will go up slightly towards the back end of the year from where we are.

Okay. And again, this quarter, the escalations were a meaningful sort of boost to your order intake. Could you say sort of what were the main contributors on the escalation front in Q1?

Yes. As ever, there's a mixture of different elements in there. We've touched in the past that we have indexation mechanisms in a number of our contracts, particularly in Brazil that cut in. And at that point, then we get an indexation uplift for the future of the year. So you get the sort of lumpiness in the escalations coming through. So for us, it's those type of contractual protections that we've discussed with the market that we have, which are standard parts of our business, which come through the escalation line in terms of what we see in the market.

Okay. And then just finally, I mean, your outlook comments, and that goes for your peers as well, are sort of a little bit different compared to other players in the oilfield services universe. So I was just wondering, is it because you kind of bridge 2025 and partially 2026 in terms of your revenue coverage? Or is there some other element that you think differentiates you from the rest of the OFS space?

I think as we discussed before, we're always very late cycle. That's where we fit into the cycling here. So the seismic guys and the drillers are the early cycle end and we're the later end. So as you touched on there, we have very good visibility in '25. We got good visibility on '26. We're reasonably sure how the pieces start to fit together, as we move into '27. Today -- we're bidding work in '28 today. So again, we don't see anything that tells us the pace at which our clients are working with us is changing. But as I said in my prepared remarks, we do understand there's a lot going on in the outside world. And there is a lot of areas which are outside our control, but we're in the cost advantage to deepwater sector. So as our clients decide where to put their money and where they put their CapEx, we know that the deepwater and ultra-deepwater is one of the most best sweet spots in the industry in terms of investment returns for our clients. So I think you're right that as a macro picture, there are a lot of questions being asked. But I think then when you look at where the dollars get spent and where the money is going down, at the moment, we are reporting as we're seeing it.

Your next question comes from the line of Kevin Roger from Kepler Cheuvreux.

I have 2, if I may. The first one, if we can come back on the alliance with BP and the comments that you had on the press release yesterday when you say that basically this new alliance aligned incentive for accelerated value among all stakeholders. I was wondering if you can share a bit with us if there is any change in the mechanisms for you in terms of remuneration, bonuses or whatever? What it means this new way of working in a way for you in terms of potential revenue margin, bonuses, et cetera? And the second one is Namcor in Namibia, just said that they have signed an MOU with you. So if you can also give us a bit of color on this MOU with Namcor and what it means for the potential future development in the country, please?

Yes. The Namcor is something that we've been working with Namcor and the authorities in Namibia for about 18 months. It's about realizing the great opportunity and the potential of the country and what's coming ahead of it. So we have a number of training agreements where we're going to take young professionals out of Namibia and take them into Subsea 7's global operations to allow them to come back into Namibia in 2 years' time, 3 years' time and allow Namibia to have a step-up in capability. So it's something we've done in a number of countries over the years and something we're very pleased to be cooperating on that topic. On the BP, it's about working in a very different way where we're much earlier in the process, but we shorten the process for BP rather than getting a third-party engineering company in to design a very planned field layout that 3 bidders can do and then go to supply chain. So we work with them in selected provinces to allow them to make their investment decisions. We are very open about the cost models and how they're built up. We have pre-agreed margin elements in there. We have a lot of joint discussions on contingency levels and such like with the clients. And then there are some incentives around early production that the client sees value from that we can share some of that as well. So a very open broad collaboration agreement, which we have with a number of other clients, by the way, which allows us all to get very, very aligned that success for our clients allows us to succeed as contractors and suppliers. Trinidad has been a great example. We started off with one job. We then did the second. We're now doing the third. Our level of understanding in that field, level of understanding of the topsides in the areas we hook up, the way of getting work done in Trinidad is getting far more efficient one of each other. So we're getting a real value of the serialization of step-outs and being there to support our clients where we need to be. So a very innovative form of working, which brings the SLB 1 Subsea and Subsea 7 capability together with BP's focus on areas that they want to grow [indiscernible].

Your next question comes from the line of Victoria McCulloch from RBC.

I wonder if you could provide any color on some of the contract sizes or prospect sizes that have changed from 4Q to 1Q in the presentation. I guess Sakarya be the one that jumps out most obviously. Is there anything you can share on how the scope has changed? Or has this just been fine-tuning of the project? And then maybe one for Mark on working capital. Can you give us an idea of how you expect working capital on the balance sheet to evolve over the year and end the year?

Mark comes first on working capital.

Yes, sure. As I shared in the prepared remarks and as can be seen from our first quarter material, we had an adverse movement in working capital of $163 million in the period. That mirrors what we have seen in the first half of the year in 2023 and in 2024, now using those as calibration points that with a deterioration in the first half of 2023 of around $400 million. And then in the second half, we recovered that to be neutral. Similarly, we saw something similar in 2024 as well. So this year, I would expect a modest deterioration again in the second quarter, but the profiles that we have within our projects in terms of milestone payments indicate that we will recoup what we have seeded in the first half of the year in the second half, and we should end the year broadly neutral. So again, you need to put that in the context of '23, '24, '25 and the significant revenue growth that we've seen in the business to have almost neutral working capital impact, which is testimony to the efforts of everyone in the organization, who are focused on this very important metric.

Thanks, Mark. Just going back then to our Subsea prospect listing on Slide 11, as we go through different bids and FEED studies and stuff, clients adjust and get their ideas about how they're going to develop it. Sakarya, as you know, is a very, very fast track field. We did Phase 1. We're doing Phase 2 at the moment. We're currently bidding what is called Phase 3A and 3B, and that's currently being submitted and under review by our clients at the moment. And what we're seeing in a lot of these very early engagements, the clients adjust the speed at which they want to do phases that they want a very, very fast delivery. And sometimes you need to then focus on doing it in stages to allow you to achieve the production profile that they're looking for. So again, there's nothing untoward happening here. The total number of wells and pipeline systems that, that particular client has got in mind, is just the sequencing in which they're doing it. And that will work its way through as they conclude with the market, whoever they pick in the market, as they contract for the next 4 to 6 months. So again, nothing to be concerned there other than general adjustments, as clients try also to optimize their economics and what they're trying to do.

Your next question comes from the line of Guillaume Delaby from Bernstein.

Maybe I'm going to be the backup in the room, if I may, by asking 3 highly simplistic questions. The first one, as of today, what is the rough proportion of brownfield projects versus greenfield projects on -- in your current backlog? This is my first question. The second question is, I guess, when we look at your slide on Subsea prospects, there are more greenfield projects, tell me if it is correct? And third, and this is the nasty -- not nasty, but slightly nasty question, is the fact what is the typical average oil price breakeven differential between brownfield and greenfield projects? What I try to assess is what could prevent your clients to move on in 2028, 2029 to go for those new greenfield projects in the new provinces?

Well, great question. And let me answer it for you. I don't have the exact split to hand, but we can give it to you back separately. But when you look at it roughly, it's a good mixture as we've always had [indiscernible] but the greenfield projects are well known on this list in the industry, which ones are the greenfields. And we've always had that mixture. It's always been our business model to provide ongoing support for clients like we just discussed with BP and Trinidad, where we have a continuity effect as well as be part of the big greenfields. For us, the -- each client makes its own decisions, but deepwater work certainly was at $60 a barrel. And it's pretty well known from detailed work with people like Rystad and Ichalkil that most of these fields work below $40 a barrel. So if you use those 2 parameters, I think, as the metrics for where you need to be. When it comes between greenfield and brownfield, it isn't quite as linear as you prefer me to give you an answer because it just depends on the resources in that particular field, how remote that field is, it's a greenfield, what other infrastructure needs to be put in, export lines or whatever or FPSO moorings and such like on one side. And then on brownfield, it's a function of outage in the FPSO. Is the capacity there? Are we already in that part of the world and we can help our clients build it out. So there isn't a very nice straightforward equation that gives us the relationship between one and the other. I guess what this portfolio shows to you, our clients are working all the mixtures and our clients have always done that. They will keep working to find which ones of these deserve their investment dollars, and we're working with them proactively to make these projects work because we work with them early and help them with their different ideas and thoughts. There's projects to the market and then hopefully, there's projects for us in that equation. So that's sort of an answer to your 3-pointed question.

Maybe a follow-up. And as a simplistic -- stupidly simplistic rule, can we say that on average, I know there is no average, brownfield projects tend to have lower breakeven price simply because infrastructure is there. Is it a fair assumption?

I wished it was, but I can't say that to you because, again, as I said earlier, it depends what greenfields are. You look at some of the fields in Brazil, historically, the pre-salt fields, and some of the very, very large fields that they can be very, very interesting to our clients. Conversely, it's the economics of scale with greenfields and the resource that's in there. Conversely, if you've got a whole infrastructure [indiscernible] FPSO, your brownfield is probably one of the best you can do. So unfortunately, I know you'd love to have an average, and I know you'd like to have an answer to that question. But I guess the point to think about though is when you look at this chart and you see what we see, and this is what we're bidding and getting ready to bid at the moment. We're not seeing it polarizing to one type of group or to the other. That's where we're at.

[Operator Instructions] And your next question comes from the line of Mark Wilson from Jefferies.

My first question is, you mentioned one-offs helping the margin somewhat in the first quarter, both in Subsea and Renewables. Guidance retained for the year, and you've mentioned a better quality of project coming through. Is there any one-offs expected in the rest of the year that you think helps deliver that margin? That's my first question. And I noticed Marjan 2 nearing completion. I just wonder if that is a completion of a project, is the sort of one-off we might be thinking about? But that's my first question. And second one, admin, I guess, lease payments of $59 million, how should we expect that lease payment trend to continue through the year?

Yes. Mark, yes, both business units benefited in the quarter through specific one-offs within the project portfolios. Most of that was related to projects nearing the end of their cycle where we had fair commercial outcomes with clients. Equally, when we near the end of projects as well, we reevaluate the cost to be incurred and the cost to be settled with the subcontractors and supply chain as well. And we had some favorable cost savings to recognize also. You will have noted that we've incurred certain one-off costs in the other way related to the merger, and we would expect those to continue over the remainder of the year. So we had certain specific projects that benefited given where they are in their particular cycle that boosted profitability to slightly greater than we were expecting as we entered into the first quarter. We maintain guidance, as you rightly highlighted. And again, we'll seek every opportunity to manage the cost and commercial attributes of the projects in order to secure what we have communicated to the market, if not succeed. But the settlements, as you know, are a customary part of the business. They're often generated by client instructive deviations from the main contract, whether in terms of sequence time and activities to be performed. So again, as you know, you followed the sector for many years. This is something that can provide a kicker to profitability at the latter part of a project's percentage of completion. Leases, yes, leases will be -- we'll see an uptick in leases. We've brought the Skandi Acergy into the fleet in April, as we had shared with the market well in advance. So leases will remain broadly similar to what we've experienced in the first quarter.

I actually -- I didn't quite get whether you expect any further one-offs in the year, though, I have to admit, Mark.

Well, I think what Mark said there is settling with clients, is a function of every project that we do. And it happens on every project. We do a final account. We do a final closure of our accounts. Historically, we've normally had a lot of that in Q4 because our clients like to tidy up their books as well. I certainly wouldn't discount it, but trying to model it is never straightforward. But there's nothing untoward here. But we did get some settlements in this first quarter, which again helped us get to where we need to be.

Your next question comes from the line of Daniel Thomson from BNP Paribas.

John, maybe one for you. Just on the client side of things, I mean, like you alluded to with BP, you work closely with a lot of your clients at the sort of portfolio level, and we'll hear from them over the next week or so. But just from your side, have you -- I mean, have those clients that have a choice to make between oil developments and gas developments? Have they asked you to reallocate engineering resource between oil and gas projects perhaps to accelerate development on the latter? Or is there sort of no change yet at this stage just in light of the macro?

I think as I said in the -- Daniel, there's no change at the moment in the dialogue. We're in Houston next week for the Offshore Technology Conference, which again is one of the main areas that the industry gets together to discuss between clients and suppliers what's going on. So again, we have a number of client meetings next week. But at the moment, we're certainly portraying to you as we're seeing it, which is no fundamental change here. But again, we are always cognizant of the fact that in good times and bad times, we have to meet the investment thresholds our clients lay out. And for us, it's the fact that we're in the cost advantaged deepwater and ultra-deepwater part of the business that gives us the confidence that these projects should pass must.

We will now take our final question for today. And the final question comes from the line of [indiscernible] from ABG Sundal Collier.

I know you don't like to be very specific about leading-edge margins, but could you see whether you see a market that supports your 2026 assessment of a 20% plus EBITDA margin also going into 2027?

I think it's a bit early for us to get into 2027. We feel very comfortable with '25. And if we thought we had to reguide the market on our view of '26, we'd have come back to you this time and told you. So again, at the moment, the main message is here, doing what we said in terms of the market. We're seeing the markets perform. We've got a good visibility on 2026 as well as '25. So at the moment, we are not seeing the elements that would come in to say there's going to be a significant change in terms of where we're at. And that's how we see it today, and that's how we're calling it today.

Your renewables margin in Q1 of 10% was quite strong, but you also mentioned helped by some one-offs. But I just wonder, in -- to my knowledge, I think you had several of the larger vessels in maintenance in the quarter. And in that respect, the Q1 margin seems very strong. Do you still see that 14% to 6% margin as sensible for the full year? Or should we think differently about that?

No, still sticking with the guidance of 14% to 16% for the year. I would say that the Q1 margin, it depends also the projects that we have in the mix. As was mentioned by Mark, EA THREE was a significant contributor. Some of the preparatory works started in Q1, even though the main assets were not yet deployed. And remembering also that, that project is an integrated project with elements of EPCI there. So there was purchasing activity flowing through also in the first quarter. So performance in the first quarter, a bit dependent on the specific projects that are running through and that was supportive during Q1 of this year.

And my final question, based on your backlog and pipeline for 2026, do you expect the number of leased vessels to stay constant? Or do you expect any changes going into next year?

At the moment, as Mark said, we've taken the Skandi Acergy, and she will go into 2026 as planned because we have the work for her. At the moment, we will keep our fleet at roughly the same size, as we've got here at the moment in terms of workload and what our needs are. We have some tonnage which will come off charter. We might take some renewed charter in, but I think the overall tonnage mix will stay roughly the same.

That was the final question for today. I will now hand the call back to John for closing remarks.

Well, thank you very much. I know it's a very, very busy day for everybody in our industry today with many, many companies reporting. But again, thank you for your time and your interest in Subsea 7 and where we're at. We feel pretty confident that we've got a good business here, and we're in the right sector of the market. And we also see some very, very interesting opportunities in the wind sector and particularly in the U.K. being again, very advantaged to us towards the end of this year. So we look forward to meeting you again in Q2. And with that, thank you very much. All the best. Goodbye.

Thank you. This concludes today's conference call. Thank you for participating. You may now disconnect.