Hello, and welcome everyone to the TechnipFMC Fourth Quarter 2023 Earnings Conference 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. I will now turn the call over to Matt Seinsheimer, please go ahead. Thank you, Sarah. Good morning, and good afternoon, and welcome to TechnipFMC's fourth quarter 2023 earnings conference call. Our news release and financial statements issued earlier today can be found on our website. I'd like to caution you with respect to any forward-looking statements made during this call. Although these forward-looking statements are based on our current expectations, beliefs, and assumptions regarding future developments and business conditions, they are subject to certain risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by these statements. Non-material factors that could cause our actual results to differ from our projected results are described in our most recent 10-K, most recent 10-Q, and other periodic filings with the U.S. Securities and Exchange Commission. We wish to caution you not to place undue reliance on any forward-looking statements which speak only as of the date hereof. We undertake no obligation to publicly update or revise any of our forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise. I will now turn the call over to Doug Pferdehirt, TechnipFMC's Chair and Chief Executive Officer.

Thank you, Matt. Good morning, and good afternoon. Thank you for participating in our fourth-quarter earnings call. I am proud to report our strong quarterly and full-year results, which really speak to the growth and operational momentum we are achieving. Total company inbound for the year grew to $11 billion. This included subsea orders of $9.7 billion, which was an increase of 45% versus the prior year and a book-to-bill of 1.5. These strong results benefited from a record level of iEPCI awards in the period. Total company revenue for the year grew 17% to $7.8 billion. Adjusted EBITDA improved to $939 million when excluding the impact of foreign exchange. This was an increase of 30% compared to the prior year. We generated free cash flow of $468 million for the year and we returned nearly $250 million to shareholders through share repurchases and dividends. While these are solid improvements, I am particularly pleased with the quality of the inbound received in 2023, with direct awards, iEPCI and subsea services together exceeding 70% of subsea inbound. We're also seeing tangible improvements in Surface Technologies. This has resulted in improved financial performance, higher cash generation, and greater consistency in delivering on our annual commitments. Anyway you look at it, 2023 was a period of strong growth for our company, and we see continued strength ahead, driven by the resiliency and durability of this cycle. The demand for energy will continue to grow. A decade of unconventional resources in North America has provided a significant portion of the world's hydrocarbons. The growth from the region will be more limited in the years ahead, driven by capital frameworks that reward higher economic returns and increased shareholder distributions. This means that the incremental production needed to support global growth will come primarily from international markets, driven by the Middle East and offshore. Looking ahead, the market for conventional energy resources will evolve differently than what we have experienced in the past, driven by three major trends: a shift in capital flows, an increased role for new technologies, and an expanded role for subsea services, all of which will allow TechnipFMC to leverage the full capabilities of our integrated solutions, differentiated technologies, and the industry's most comprehensive subsea service capabilities. Looking more closely at these major trends, let's start with the shift in capital flows. We expect to see continued strength in spending both in land and offshore markets. However, the dynamics will differ across major markets as capital flows are typically a function of returns and access. In North America, the industry has access to resources, but economic returns will continue to be challenged outside the most prolific basins. We believe this will result in more modest growth in the region. Opportunities in the Middle East benefit from strong economic returns that will drive continued growth. That said, the number of operators that have access to these attractive resources is far more limited, which brings us to the offshore markets. Here, we believe much-improved economic returns and broad operator access to deep-water resources will attract a growing share of global capital flows. And with more than 90% of our total revenue generated outside the North America land market, TechnipFMC stands out as the pure-play equity to address this opportunity. While the strength of these trends is partly reflected in our current backlog and revenue guidance, we have high confidence in the durability of the market over the intermediate term. In 2024, we remain on track to meet our prior guidance for subsea inbound, with current year order expectations approaching $10 billion. Today, we are also increasing our expectations for subsea inbound over the three-year period ending 2025 to reach $30 billion, a 20% increase versus our prior view. Looking beyond capital flows, we expect technology to also play a bigger role in spending behavior. Here, TechnipFMC is focused on developing technologies for both conventional and new energies to drive market expansion. More specifically, we are using technology to drive further innovation in the offshore market, creating new growth opportunities. A clear example of innovation is the Mero 3 HISEP contract, which we were awarded just last month. The significance of this project for the subsea industry cannot be overstated. It will be the first to use subsea processing to capture CO2 directly from the well stream for injection back into the reservoir. Importantly, this will all take place on the sea floor. In addition to reducing greenhouse gas emission intensity, HISEP technologies will increase production capacity by debottlenecking the gas processing plant that currently resides on the FPSO. By moving the gas processing entirely to the seafloor, future FPSO topside designs can be further simplified, driving significant improvement in project economics. HISEP is a major milestone for the subsea industry and for TechnipFMC. This project plays to our strengths. HISEP will allow us to demonstrate how technology innovation, project integration, and partner collaboration enable our meaningful participation in the energy transition while remaining aligned with our strategic priorities. It is the first iEPCI project ever awarded by Petrobras. And it builds upon our strong order momentum, starting the year with an iEPCI award that exceeded $1 billion. Finally, the third major trend driving subsea market growth opportunities can be found in services. Today, subsea fields host more than 7,000 subsea trees and associated infrastructure, including manifolds, control systems, umbilicals, and flexible pipes. This list is certainly not inclusive of all major components of a subsea production system. However, it does highlight the size and scale of the industry’s large and, more importantly, growing installed base. TechnipFMC’s global services organization plays a critical role throughout the entire life of the field, from system installation to maintenance intervention and production optimization and all the way through life of field. Our 2023 results clearly demonstrate that our strategy to enhance this resilient, growing, and high-return business is delivering real value, with our services revenue having achieved over $1.5 billion for the year. In summary, we close out a solid year having delivered many notable achievements. Subsea inbound orders increased 45% versus the prior year and included a new record for iEPCI awards. This growth in orders also drove a 50% increase in subsea backlog to over $12 billion, with high-quality inbound supported by further improvement in our financial returns. Our growth in full-year operational results reflects strong momentum that continues into 2024. We have entered an unprecedented time for the development of conventional energy resources, driven by three major trends: a shift in capital flows, which we believe will largely be directed to the offshore and Middle East markets; an increased role for new technologies as shown by the MERO 3 HISEP award; and an expanded role for subsea services driven by the needs of growing and aging infrastructure. Importantly, these trends underpin the 20% increase in our expectation for subsea inbound over the three-year period ending 2025, which at $30 billion will provide additional growth in backlog and further expand the execution of our project portfolio through the end of the decade. I will now turn the call over to Alf.

Thanks, Doug. Inbound in the quarter was $1.5 billion, driven by $1.3 billion of subsea orders. Revenue in the quarter totaled $2.1 billion. EBITDA was $245 million when excluding a foreign exchange loss of $26 million and restructuring impairment and other charges totaling $10 million. Turning to segment results, subsea revenue of $1.7 billion increased modestly versus the third quarter. The increase in revenue was due to higher productivity in the Gulf of Mexico, Asia Pacific, and Africa, driven in part by accelerated conversion of several projects from backlog. The increased activity was largely offset by seasonal factors that impacted vessel utilization. Revenue for subsea services modestly increased due to strength in asset maintenance and ROE services in Norway and the Gulf of Mexico. Services revenue was also less impacted in the quarter by typical offshore seasonality, particularly in the North Sea. Adjusted EBITDA was $225 million, with a margin of 13.1%, down 200 basis points from the third quarter due to lower vessel-based activity and a mix of projects executed from backlog in the period. For the full year, subsea revenue grew 18% versus the prior year with adjusted EBITDA margin up 180 basis points to 13.3%. In Surface Technologies, revenue was $357 million in the quarter, an increase of 2% sequentially. The increase in revenue was driven by higher activity in international and North American markets, both benefiting from higher wellhead equipment sales. Adjusted EBITDA was $52 million, a 5% sequential increase benefiting from increased contribution from international services and higher wellhead sales. Adjusted EBITDA margin was 14.7%, up 30 basis points versus the third quarter. For the full year, Surface Technologies revenue was up 12% versus the prior year with adjusted EBITDA margin up 230 basis points to 13.6%. Turning to corporate and other items in the quarter, corporate expense was $33 million, when excluding $5 million of charges. Net interest expense was $13 million and benefited from increased interest income in the period, driven in part by strong cash generation. Tax expense was $54 million. Lastly, foreign exchange loss was $26 million, the majority of which was related to the significant devaluation of the Argentine peso. Cash flow from operating activities was $701 million. Capital expenditures were $72 million. This resulted in free cash flow of $630 million in the quarter. Free cash flow for the full year was $468 million, above the high end of our guidance range. When excluding the impact of foreign exchange, we converted 50% of adjusted EBITDA to free cash flow, achieving the cash conversion rates we had previously targeted for 2025. Total shareholder distributions were $77 million in the quarter and $249 million for the full year. We ended the period with cash and cash equivalents of $952 million. Net debt declined more than $500 million to $116 million. In November, we announced an agreement to sell our Measurement Solutions business for $205 million in cash. We now expect to conclude the transaction by the end of the first quarter, subject to customary closing conditions. Moving to our financial outlook, we have provided detailed guidance for the current fiscal year in our earnings release. I won’t speak to all the details, but will provide some context for certain items for the full year and first quarter. I will begin with Subsea. At the midpoint of our full-year guidance range, we anticipate revenue of $7.4 billion with an EBITDA margin of 16%. This represents a 270 basis point margin improvement from the prior year. Our outlook also anticipates contingent growth in subsea services revenue to approximately $1.65 billion, achieving this level one year ahead of our previous target. For the first quarter, we anticipate subsea revenue to decline low-to-mid single-digits due to more typical seasonal activity patterns, and EBITDA margin to be in line with fourth quarter results. Turning to Surface Technologies, at the midpoint of our full-year guidance range, we anticipate revenue of approximately $1.275 billion with an EBITDA margin of 14%. This guidance assumes we complete the sale of our Measurement Solutions business by the end of the first quarter. When excluding the impact of this sale, as well as the exit of certain geographies and portfolio rationalization in the Americas, our Surface Technologies revenue is anticipated to grow approximately 5% year-over-year. For the first quarter, we anticipate revenue to decline approximately 10%, compared to fourth-quarter results, with an EBITDA margin of approximately 13%. We anticipate full-year corporate expense of $115 million to $125 million. In 2023, the company initiated an ERP system upgrade. Our corporate expense now includes approximately $10 million in annual costs related to the implementation of the upgraded system. We expect to incur a similar cost each year until completion of the project in 2027. We anticipate capital expenditures of $275 million, which is just over 3% of revenue at the midpoint of our guidance range. Finally, we are guiding free cash flow for the full year to a range of $350 million to $500 million. This includes approximately $170 million for the remaining payments related to the resolution of all outstanding matters with the PNF. Excluding these payments, the midpoint of our free cash flow guidance would approximate $600 million. In closing, when our guidance items are taken at the midpoint of the range, we anticipate total company EBITDA of $1.25 billion for the full year. This represents EBITDA growth of 33% compared to the prior year when excluding foreign exchange. I also want to stress that we expect to achieve this significant growth, despite the impact of the strategic actions taken in Surface Technologies and the incremental spend related to the ERP system upgrade. This is also the second consecutive year for free cash flow conversion of nearly 50% when excluding the settlement payments. We expect this to drive growth in shareholder distribution of at least 35% and a further reduction in net debt.

Thank you. Your first question comes from the line of Arun Jayaram of JPMorgan Securities LLC. Your line is open.

Yeah, good morning, Doug. I wanted to first start with the increase in your long-term or three-year order guide; you raised that from $25 billion to $30 billion. I was wondering if you can comment on what drove the increase and perhaps give us a sense of how much of this was your expectation for more market share versus just the growing TAM in terms of Subsea and offshore FIDs?

Sure, good morning, Arun. It's really a combination of both. Clearly, both the total market size is increasing and, as you know, our share of the market continues to increase due to the unique offering that we provide. Look, we are seeing much greater visibility into the durability of the cycle and much greater confidence when we kind of risk-weight opportunities. When you're in a direct negotiation, there is no competitive tender, as stated in my prepared remarks, which represents over 70% of our subsea business. You obviously have a much higher ability to properly risk-weight for those opportunities. You see the outlook slides that we provide, and the size of the markets is solid and is growing. It's just really we're in a privileged position, which we are humble about and honored to have this position, and we offer our customers a clear line of sight to improve subsea project economics that are unique to our offering both in terms of our Subsea 2.0 architecture and our iEPCI offering that reduces their cycle time by 12 to 14 months on a deepwater project, thus vastly improving their economics.

Great. My follow-up, Doug, we're intrigued by the MERO 3 project award; I know you announced just a bit earlier in the quarter. But I was wondering if you could just talk a little bit about some of the unique technology that you're bringing to the table for this, and it seems like an application that could open up a world of new opportunities despite taking some of the processing and separation to the seafloor, as you mentioned; it would perhaps reduce some of the needs at the surface in terms of the design of the facility. So I was wondering if you could maybe comment on the technology and perhaps the scope here of future opportunities and what this could open up for TechnipFMC?

Sure, and thank you for the question because the award was announced earlier. We haven't had a chance to talk about it here in this forum. This was the first opportunity. So, I'm very excited. As I pointed out, I think it - we said it's really, really unique both for the industry, as well as for our company. And I think understanding, as you said, what are some of the actual award and then what is enabled by that? So let's start with just some of the highlights. Yes, one of the bottlenecks that we see in greenfield developments as the offshore market continues to grow will be the delivery of the FPSO. FPSOs are complicated, and there are only a limited number of providers of those FPSOs. Clearly, they are becoming the long pole in the tent in terms of the project cycle time. Our approach to ensuring that deepwater economics remain privileged is driving our customers' global capital spend. We are focusing on doing everything we can to address the cycle time, as well as reducing the risk of delivering the projects and ensuring they're delivered on time. An example of that would be, the FPSO itself is an intriguing unit. But the complexity is really in the topsides configuration that you put on top. You do that because you either have to separate water from oil or you have to treat the gas or you have to separate, in this case, high CO2-rich dense gas from the flow stream. If you can do that on the seabed, it has many advantages, one being simplifying the FPSO, therefore reducing the risk of it becoming a bottleneck in terms of driving further improvements in cycle time. Secondly, there is obviously more real estate on the seafloor. We can do things horizontally, whereas, if you're on a ship, you are constrained to doing things vertically. Any sort of vertical construction costs more than horizontal construction. So in the simplest terms, we just have more real estate to play with. And just as importantly, this is CO2 mitigation; this is about reducing greenhouse gas intensity. This is about separating the CO2 on the seafloor and reinjecting it into the subsurface. It never sees the atmosphere. And remember, it's at the bottom of the ocean, on the seafloor, in a closed-loop system where we can separate out the CO2 and reinject it, thus delivering a much lower greenhouse gas intensity for the project. Furthermore, I also mentioned, and I think it's important to point out, this is the first-ever iEPCI, which is our unique commercial model, the integrated commercial model. The first time Petrobras is using this model. So, you're absolutely right. We’ve done separation projects in the past. We've done boosting. This is a unique combination of advanced separation, the first time for CO2 specifically, as well as boosting and reinjection and putting this all together into an integrated system architecture is something that we are extremely proud and excited to be working on with Petrobras that deliver this. This is being done under the premise of design one, build many. So as you pointed out, this can start to open up all sorts of other opportunities as we move forward.

Thanks, Doug. I'll turn it back.

Great. Thanks. Good morning, Doug. How are you?

Good morning, Dave. Great. Thank you.

Just to follow up on that – Arun’s question on the subsea processing. Subsea processing we've been talking about for a long time. If I go back more than 10 years, you guys started introducing this. The cycle kind of ended before this really became mainstream. So maybe can you just talk about what’s different today about subsea processing versus ten years ago? Maybe it’s just the CCS part. How effective was it before? What's changing? I'm just very curious why the adoption today is, you've talked about the FPSO, but I seem to recall that was the whole point in the first place. So why didn't that catch on before or maybe it did? And why is it catching on now?

Dave, I wouldn't disagree. I would say the subsea processing market has maybe under-delivered in the past, to be very blunt. What we're looking at here is a completely different application. And as you know, greenhouse gas intensity and CCS open up a completely different dynamic in terms of the thinking around project sanctioning. So, let's just say it adds an additional dimension, which is one reason we believe that this is a new market; I would almost not put it under the bucket of subsea processing, even though it's using many of the same technologies, there's multi-phase pumps and separation, etc., but it is a unique application. Secondly, there is unique technology involved here, and we've been working with Petrobras since 2016. We have an R&D center for subsea in Brazil, which gives us the unique ability to work closely with Petrobras in developing and bringing this technology to life. Our experience in terms of system integration and putting together the entire package gives us a reason to believe that this application, and I'm going to go back to point one, when you add this other dimension into the project’s sanctioning criteria, I believe it makes the decision lean more towards the subsea.

And as you're saying it takes cost off the FPSO, as well as the idea to help lower the overall development cost of the project. Is that sort of the intent here?

Well, cost, but more importantly, it’s going to allow you to build an FPSO with a basic topside in a fraction of the time that it takes to build one with a full gas processing plant on top. It doesn't - the time isn't spent on building the hull and the storage and the offloading system. The time element is in the topside configuration, which as you know is often done at a different yard than the hull. It's just much more complex. Our whole focus is on helping them improve their economics by shortening the cycle time. That's the real focus today.

Okay. Thanks. And if I go back to the awards, your two-year outlook on subsea awards out there, you essentially added about $5 billion in orders to your next year view. I'm just curious. In terms of your iEPCI awards, you're saying 70% today. Does that number go up over the next two years? And I'm assuming, are you already working on these projects? Is that kind of where your confidence comes from? Because I know these iEPCI awards start at a very early stage. Is that kind of where this is all coming from? And if I can just pile on one more question in there: how is pricing evolving here? We're in a consolidated market now. Is that starting to show up in the bids? Sorry I packed a lot in there.

No problem, Dave. I will try to address it as well as I can. So, the 70% over 70% that we refer to, as you know, is the direct awards, which is a combination of those iEPCIs that are direct awarded; the majority of ours are direct awarded, with very few going out to competitive tenders, as well as our subsea services and other direct awards from our alliance partners. On the iEPCI portion for us, it is about 50% of our total. Do I see that increasing? Yes. What gives me the confidence and visibility is, remember, they typically almost always in our case start with an integrated feed study, the integrated front-end engineering and design, which is two to three years old. So what gives us the unique visibility is we can see because we’re at the table much earlier. In many cases, we’re doing an integrated feed study and iFeed. Contractually, we don’t do iFeeds unless it will be direct awarded to us because it wouldn’t make sense for us to do an integrated feed study demonstrating the value of integration if we weren’t going to execute the project. So, in the front-end engineering studies, which are at a very robust level right now, the percentage of integrated feeds, which will convert into integrated EPCI studies, continues to grow, which again gives us that confidence. We know the client; we know the basin. We know that working together, if we can achieve the right economics for the project, then that will turn around and be direct awarded to our company. I would say we have great confidence, and as you know, we give our inbound outlook; it’s by project, by name, and there’s a great degree of confidence in the numbers that we put out there in our ability and consistent track record of delivering against them. We have the visibility from the feed studies that gives us the confidence. We continue to see the direct awards going up. And I’ll make one other kind of comment for you, Dave. It wasn’t part of your question, but I do think it’s interesting. Just this year, we’re not that far into the New Year. I will tell you the number of very large greenfield projects that we are already in the front-end engineering and/or commercial tendering stage or in some level of a commercial negotiation stage because, again, if they are direct awards, there is no tender. I have never seen anything like it. The cadence and the size of the projects are quite remarkable, and it will be one record after the next. And by the way, I’m not counting the emerging countries here, and this may include Tanzania, Colombia, etc. I’m saying this is within the traditional or known basins that we’re operating in today. There are a lot of big projects coming in, and we think we are working very closely with our customers to bring those to life.

And Doug, is that incremental to the orders that you're highlighting further out to 2025?

Well, no, not necessarily. Obviously, if we are in direct negotiations today, it's probably going to happen before then, but you raised another good point, and I don't want to be too verbose here. However, we are, and I've mentioned this on past calls, that started about nine months ago. Our clients want to secure our capacity. They understand what we have is a unique offering. So they’re not only talking to us about the current award, but in most cases are talking to us about the future phases, where the future tie-ins may be. So, yes, part of it is in, but yes, we are also looking and working on awards that will be coming beyond 2025.

Thanks a lot, Doug.

Thank you. My first question, Doug, is on the subject of the additional awards and the $30 billion after 2025 you talked a lot in the past about the manufacturing process you've put in place as well to be able to deliver all the services you've built. So can we talk about if there is any impact to the expected margin from this additional, if not larger market outlook? That's my first question. Thank you.

Sure. Good afternoon, Mark. I believe you're going to the capital expenditures angle, and I'm going to go there even. I hope that's where you wanted me to go, but look, because of the Subsea 2.0 and the configure-to-order model, some of which I believe you've had an opportunity to witness yourself, it allows us to achieve higher rates of throughput within the existing facilities without having to spend additional capital. So, as always, there will be capital spent on replacing certain machine tools, etc. But in terms of roofline capacity or major expansion or major capital investment to deliver this growth, that is not the case. It would be within our normal capex expenditures.

Thanks for that. Actually, where I was really looking is on the EBITDA margin you'd be expected to generate, if we're not having to put in more investment yielding economies of scale, frankly from higher throughput coming through within your margin expectations. Thanks.

I would agree with that statement. Fully agree with that statement.

Okay. Thank you very much. And then lastly, looking further ahead, and obviously, you've spoken to a lot of technology coming through, the gas processing, subsea separation, CO2 injection. There are new basins emerging, clearly bringing some things in Brazil, which is now been out there for a few decades now. But there are new basins coming through with new technologies, new levels to go to, so many kinds of depth and with gas processing. Where would you suggest the industry is looking in terms of the next technological step? Is it in terms of going deeper, doing more with gas, or indeed electrification just generally? Thanks.

Mark, I am laughing because you are spot on; it's as if you were in our technology review with our Chief Technology Officer the other day. The only thing I would add to what you said is one actually enables the other. So deeper and electrified are complementary, and electrification will allow us to go deeper. We've talked about electrification in the past in terms of allowing us to have a longer step-out. But it’s just the ability to transmit hydraulic fluid and the response time, because the further you push it, the more friction pressure, the more delays, if you will, you have to get a response from hydraulic actuation versus electric actuation, which can be done very, very quickly. So I went so certainly deeper. Now it is not only electrification, but electrification will enable deeper. There are also other aspects to going deeper, particularly when you think about things like flexible pipe design. We have the only flexible pipe that will work at the depths that these emerging basins are being developed. It takes a very, very unique design. There are other technologies we're working on that will also be very beneficial as we move into some of the new basins, which indeed will be at greater depths than we've routinely operated at today.

Hi Doug. Thanks for taking my question and maybe continuing on the sort of technology front. Just looking at West Africa, there are a few prospects in your list in areas like Angola and Nigeria that have been set there for quite some time. When we know the operators have been really strict when getting those to a point where project economics are acceptable, I was kind of wondering how many of those projects you've refreshed offers on recently or will in the near future? And if you found ways within your works to go via through technology or something else to bring those costs down to enable sanction while still maintaining the attractiveness to yourselves. Thank you.

Good afternoon. That’s a very fair question, one we look at often, and I’m actually looking at the subsea opportunity list as I answer your question. So first of all, as you know, to be on the list, there’s an expectation that it would reach FID within the next 24 months. That expectation is aligned with the customer. In some cases, projects are done here because they’re confidential or projects that are going to be direct awarded to our company, so they are not on the list. I will tell you looking at the list right here in front of me, the same one you are, I can confidently say, all but one, as you said, are either going through a refreshed feed study and/or in some level of a commercial negotiation. So actually, the vast majority of them. I know there’s been some of these have been here a while and some of these have been discussed many times over. But let’s just be blunt; that was before iEPCI, that was before Subsea 2.0. When you can deliver a project 12 to 14 months shorter cycle time, it has a big impact on the economics. There’s other reasons specific to the client that they may be wanting to move a project forward, which is not anything I would comment on. That's up to them to comment. But that’s what we’re providing to help them bring these projects to a stage that the customer could, if they chose to, FID the project.

Thanks. Yeah, that makes sense. And maybe one follow-up on Brazil. I wondered if you had any comments on how your bidding strategy in Brazil may have changed just in light of one of your competitors being barred from contracting with Petrobras for the next two years. I mean, do you feel that you guys might be getting some more work there? Or are the opportunities limited?

Look, we're a company that has very close relationships with our clients. We always look towards the future, not just at the present opportunity and treat our clients with respect. We expect them to treat us with respect, and we have a very strong relationship with Petrobras. We are very proud of the work we're doing, including the award of their first-ever iEPCI and the first-ever application of HISEP in Brazil. I would just say that we'll continue to treat our clients the way that we appreciate them treating us, and we believe that is the right way to do business.

Right. Thank you. I’ll turn it over.

Hello everybody.

Morning, Kurt.

So, hey, Doug, kind of bigger picture question for you, potentially, right? So, last June, you referenced you had increased visibility on potential projects that extend out toward the end of the decade. You continue to reiterate that in each and every conference call. Yet there seems to be a significant disconnect between what investors want to believe and what you are actually seeing predicated on the discussions, the game plan that your customers have. It's probably the biggest disconnect I've ever seen in my 35 years in this business. So, you’ve given a lot of input and commentary and data points around what you’re seeing, but what do you think is driving the conviction of your customer base to pursue these projects for oil production that's going to come online in three to five years, when everybody's freaking out about what oil demand is going to do? So, what are the oil companies seeing that the investor base may not in your personal opinion?

Kurt, I learned a long time ago is to not speak on behalf of my clients. I can only give you my perspective. I think everybody has their long-term energy outlook. People understand that the demand is going to go up and the rate of change of the energy mix. When you look at those two through a realistic lens, you come to a conclusion that these are probably the right investments to be making to ensure that the world has access to reliable and dependable energy as we continue our journey forward. These are solid projects with solid economics, and they are created with the confidence they have because of what we have done as a company and by the creation of TechnipFMC and our ability to deliver these projects consistently on schedule or ahead of schedule, which again is 12-plus months faster than anyone else can do it because they're doing it the old-fashioned way. It's just a very unique scenario, and they have a much higher level of confidence in our company. It's hard for me to say that; I wish they always did, but when we were all doing bespoke work like the rest of the market is doing today, you have confidence until something goes wrong because you've never done it before. We are not doing bespoke anymore; we are doing configured order versus engineered order. So, their level of confidence is there. We are giving our customers that level of confidence to help with their investment decisions. I don't want to weigh in on the disconnect; maybe I agree, but the reality is people are recognizing that this is the new reality. We will keep our heads down, execute, inbound execute, continue to grow, and continue to innovate. We will return to our shareholders and will continue to do so. We think doing what is right will ensure that we continue to be rewarded.

I appreciate that insight. Doug, now to follow up on that right, so you've indicated that your iEPCI process and integrated processes reduce cycle time by 12 to 14 months. Is that maxed out, or how much more can you reduce that cycle time? How do we think about that?

It's a continuous innovation curve. We saw this in the unconventionals. In the past, when I was in the fracking business, it was single-stage, single well, and most of you could do two a day because you had a rig down and would move to the next well; now we went to 24-hour cycles then to simul fracking, and now trimul fracking. There will continue to be innovation; we are in the very early stages versus what we saw in productivity curves in unconventionals. Think about what we will do in subsidies, and it will be no different. We're just at the very early stages of it.

Great. Appreciate it. Thanks for your insights, Doug.

Yes, good morning, Doug and Alf.

Good morning, Scott.

I wanted to circle back on margin. So, you’re forecasting robust 16% this year, then to your 18% forecast in subsea in ’25. Doug, you talked about 18% being closer to normal versus close to the peak. So now, with this raised order intake outlook, how should we be thinking about the margin expansion potential into ‘26? Can you extrapolate that trend literally and assume something close to 20% in ‘26? Would recent awards support that level of margins in a few years?

Scott, I had a look at my watch for a minute and just reminded myself of the year we are in. Look, Scott, I appreciate the question. Clearly, based upon the whole discussion we've had thus far, the market is there, our position in the market is there, our unique offering is there, the direct awards are there. We just talked about that there is more leverage to come both in terms of cycle time, which will improve project economics and improve the total available market. There’s leverage related to our own internal cycle time and benefits as we convert to 2.0 and iEPCI, neither of which are at 100% today and they will never be exactly 100%. But they will certainly be more than they are today. We remain very confident that we will continue on the path we’re on and have certainly, as we've said before, made comments that are major milestones on a more ambitious journey. No less confidence, if anything, even more conviction.

I appreciate it. I thought a few years out, but had to ask. I was going to come back to the subsea separation to talk about again. Can you help us think about the content uplift or STI by putting the separation and reinjection on the seafloor? I imagine there's a range based on what is done on the seafloor and the content of the production stream. What’s the reasonable range for us to think about in terms of content uplift?

The way I would view it is we know that it's a billion-dollar-plus award because that's how we classify it. Right? So that was being done somewhere else and, if you will, on the topside today. You think of it at a minimum; you're taking functionality that was under the scope of someone else and putting it under our scope, and then we're putting it on the sea floor. That's kind of one aspect that I would think about in terms of margin expansion. If you say, what is the scale of that? Well, this is actually a brownfield project, not a greenfield project. So this is a brownfield project where you’re seeing an incremental billion-dollar-plus scope coming to our company as a result of this unique offering and capability. You can't multiply that by every brownfield, but if you multiply it by just a few, that’s a pretty dramatic uplift right there, Scott. Additionally, this is a billion-dollar reward that doesn’t include a single Christmas tree. We’ve often in the past thought about trees and trees and tree counts. There’s a billion-dollar reward without a single tree. It shows how this market is expanding favorably for the industry and for our company.

I appreciate all the color. Thanks, Doug.

Yes. Hello, Doug. Two questions, if I may. How should we think of your 2025 subsea intermediate guidance when it comes to revenues you had in mind at $8 billion? Are you ready to give us enough lift to that?

Sure. Good afternoon, Bertrand. I'll touch on the 2025 question and then I'll turn it over to Alf if you want to add any color and then he can touch on the free cash flow as well. On the 2025, look, we updated our inbound target through the end of 2025; that obviously gives greater conviction in the numbers that had previously been shared around 2025. I can give you a little better view of something very compelling at a total company level. There are some things happening in our Surface business as an example, and there are implications to selling the business, but there are also positive things happening on the Subsea side. Without giving any specific comments on the revenue target, I think we can give you directionally something very compelling. I'll pass it over to Alf.

Yes, thanks, Doug. Maybe just to put this in context regarding the subsea situation, we are coming off a strong growth in earnings this past year. We are looking forward to another strong year in 2024. We saw backlog growth of 50%, and not only did the backlog grow, but the quality of that backlog grew. We are building strong average margins in the backlog. On top of that, we are upgrading the previous $25 billion target to $30 billion. And when comparing that with positive momentum in our subsea services business, all that adds up to greater confidence in the overall subsea outlook. As Doug mentioned, we do expect lower surface revenue due to the Measurement Solutions sale and some of the rationalization we've done over the last 12 to 18 months. We clearly expect to offset that by a higher relative earnings mix coming from subsea in 2025. I may have skipped your free cash flow question, so let me get back to that. First of all, you appropriately noted that in part, the Q4 inflow was indeed driven by advance payments or progress payments on our subsea business. I don't necessarily consider it a negative to build contract liabilities; I see it as a positive that we can run our business on a very neutral working capital basis for the whole company. When you look forward, I certainly don't expect the same kind of builds in contract liabilities, but I do expect us to continue to be neutral to slightly positive in working capital for the next year.

Hi, good morning, Doug and Alf. Maybe Doug, if you don't mind, I think I don't remember if you said this or Alf said this in the prepared remarks, but subsea revenues were really strong in the fourth quarter. I think you noted accelerated conversion of backlog in Q4. But Doug, can you comment on whether that's project-specific, one-off timing-sensitive thing in the fourth quarter? Or is that a trend that we should be mindful of in terms of timing of converting backlog into revenue going forward in subsea?

Sure, obviously a good story, and I'm going to let Alf tell the story.

So first of all, you're absolutely right. We did have a very strong revenue quarter for subsea, basically holding flat to the prior quarter. Partly of that is due to experience with less of the typical seasonal factors we do have as headwinds going from the third quarter to the fourth quarter, but we did have some projects that accelerated revenue more than expected. I would say this includes a mix of what I want to term legacy projects that are executed out of the backlog, hence, maybe that the margin mix was not necessarily positive for the quarter. But it really was nothing that would affect any of the guidance that we have given forward-looking, including anything we discussed about how our backlog will evolve over the next two years.

Okay. Awesome, Alf. Thanks for clarifying. And then, just one more. I know we've spent a lot of time on the subsea processing today, but maybe an unrelated technology question. You also won the Sparta project recently, and I think if I'm not wrong, this is only the third 20K PSI project in the Gulf. The Anchor and Shenandoah were the ones; you won Shenandoah. How should we look at that opportunity? Because there is a good pipeline of high-pressure projects in the Gulf. How should we look at that opportunity going forward, Doug? And how can TechnipFMC benefit from that?

Excellent question; that's spot on. The third high-pressure project in the Gulf of Mexico, clearly, is starting to move forward. We were excited to get the first award, which was the Shenandoah project as you pointed out. This will not be our first delivery of 20K, but it will be the first 20K iEPCI project. So super excited to have that, as well, to set that new milestone. Now going forward, as you know, Chevron, Shell, BHP, and LLOG have assets, most of which we think have high probability of additional projects going forward. We don't speak to it as a new frontier, but it is a new horizon within an existing frontier.

And with that, I will turn the call to Matt Seinsheimer for closing remarks. Thank you. This concludes our fourth quarter conference call. A replay of the call will be available on our website beginning at approximately 8:00 P.M. Greenwich Mean Time today. If you have any further questions, please feel free to reach out to anyone on the Investor Relations team. Thank you for joining us. You may end the call.