Thank you for standing by, and welcome to the TechnipFMC First Quarter 2024 Earnings Conference Call. I would now like to welcome Matt Seinsheimer to begin the call. Matt, over to you. Thank you, Mandeep. Good morning, and good afternoon, and welcome to TechnipFMC's First Quarter 2024 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. Known 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 first quarter earnings call. I am very pleased with the strong performance in the quarter, which further highlights our continuing success in delivering on our commitments. Total company revenue for the first quarter was $2 billion. Total company adjusted EBITDA was $257 million, with an adjusted EBITDA margin of 12.6% when excluding foreign exchange impacts. Total company inbound orders in the quarter were $2.8 billion. In Subsea, we had a solid start to the year, with first quarter orders of $2.4 billion, representing a book-to-bill of 1.4. Importantly, a significant portion of our inbound was driven by new technologies, several of which were industry first for Subsea that will help unlock opportunities in both new and mature offshore basins. In January, we announced our first iEPCI for Petrobras, this one utilizing subsea processing for the Mero 3 HISEP development. The project represents a major industry milestone, as it will be the first to use subsea separation to capture CO2 directly from the well stream for injection back into the reservoir, all of which will occur on the sea floor. During the quarter, we were also awarded the first iEPCI to utilize a 20K production system, this being for Shell's Sparta project in the Paleogene play in the U.S. Gulf of Mexico. The 20,000 PSI production system includes new technologies required to meet the demands of high pressure, high temperature reservoir conditions. This marks our third award for 20K production equipment, as clients look to produce from deeper waters and reservoirs in the maturing basin. The Paleogene formation spans the central and western regions of the Gulf of Mexico, with reservoirs located in water depths that exceed 1,500 meters and generally exhibit higher pressures. The Paleogene has become one of the most productive and fastest-growing sources of supply in the Gulf, and it is estimated that 1 billion barrels of discovered reserves will require the use of 20K technology for development. We expect additional projects to successfully move forward over the next 24 months, representing yet another opportunity set for our company. And finally, we announced an award from the Northern Endurance Partnership to deliver the first all-electric subsea iEPCI, which is anticipated to be inbound in the second half of this year. The partnership, which is a joint venture between BP, Equinor, and TotalEnergies, is building CO2 transportation and storage infrastructure for carbon capture projects in the UK's East Coast Cluster. Our all-electric solution will collect and feed the pressurized gas into an aquifer for permanent storage. All-electric systems drive simplification of the field design, enabling the reduction of infrastructure and installation time through the removal of hydraulic components and simplified umbilicals. The technology also enables the development of projects over long distances. With Northern Endurance, the power and controls to the subsea equipment will extend 145 km from the onshore host facility. The award of an entirely all-electric subsea system is a significant achievement for both our company and the industry. Mero 3 HISEP, Sparta, and Northern Endurance are all strong examples of our differentiated technology portfolio. Each of these projects provides a unique solution to an industry challenge, and it is this unique combination of innovative technologies and integrated execution that is creating new market opportunities for our company. While project selectivity remains a critical objective, it is even more important that we successfully deliver on time and on budget as promised. As demonstrated by our financial performance in the quarter, operational execution across the portfolio continues at a high level, driven in part by this focus on project selectivity and the favorable impact it is having on the quality of orders in our backlog. Having both the right backlog and strong execution gives us confidence that we can capitalize on the strong market and achieve our financial targets. Finally, we completed the sale of our Measurement Solutions business in March. In keeping with our commitment to shareholder distributions, a significant portion of the proceeds were allocated to repurchasing $150 million of shares in the first quarter. This brings our total shareholder distributions to $520 million in less than two years. Given this acceleration in share repurchases, we now expect total shareholder distributions in the current year to grow at least 70% when compared to the levels achieved in 2023. I will now turn the call over to Alf. Thanks, Doug. Inbound in the quarter was $2.8 billion, driven by $2.4 billion of subsea orders. Total company backlog increased sequentially to $13.5 billion. Revenue in the quarter was $2 billion. EBITDA was $257 million, when excluding a gain on the sale of our Measurement Solutions business of $75 million, restructuring impairment and other charges totaling $5 million, and a foreign exchange loss of $4 million. Turning to the segment results, in Subsea, revenue of $1.7 billion was largely flat versus the fourth quarter. Higher project activity in Brazil and the Gulf of Mexico was largely offset by lower activity in the North Sea and Asia Pacific, and reduced services revenue due to typical offshore seasonality. Adjusted EBITDA was $242 million, with a margin of 14%, up 90 basis points from the fourth quarter. The sequential increase was driven by strong execution and improved earnings mix from backlog. In Surface Technologies, revenue was $307 million, down 14% sequentially. Revenue decreased due to the closing of the sale of Measurement Solutions before the end of the quarter, lower activity in North America, and portfolio optimization in Latin America. Adjusted EBITDA was $41 million, a 21% decrease from the fourth quarter, driven by lower revenue from Measurement Solutions and lower activity in North America. Adjusted EBITDA margin was 13.5%, down 120 basis points versus the fourth quarter. Turning to corporate and other items in the period. Corporate expense was $27 million, when excluding charges of $5 million, which were primarily transaction-related costs associated with the sale of Measurement Solutions. Foreign exchange loss was $4 million. Net interest expense was $13 million, which benefited from higher average cash balances in the period. Tax expense in the quarter was $50 million. Cash required by operating activities was $127 million. The outflow follows the typical seasonal pattern of our business. Additionally, cash flow in the period included a payment of $56 million to the PNF. Similar payments will occur in the second and third quarters and will fulfill our remaining obligation. Capital expenditures were $52 million. This resulted in free cash flow consumption of $179 million in the quarter. As Doug highlighted, we completed the sale of the Measurement Solutions in March. Proceeds from the sale were $186 million, with the majority being used for share repurchase. This drove a significant increase in total shareholder distributions in the first quarter to $172 million, which included $150 million for share repurchase and $22 million in dividends. We ended the period with cash and cash equivalents of $697 million. Net debt was $327 million. Now, I will provide some thoughts on our outlook, starting with the second quarter. For Subsea, we expect to benefit from the typical seasonal uplift as well as improved margins in backlog, with sequential revenue growth of approximately $200 million and margin expansion of approximately 250 basis points. For Surface Technologies, we expect revenue and adjusted EBITDA margin to be in line with the first quarter. This includes the impact of the sale of Measurement Solutions. Now, I will also give you an update to our full year outlook. Given the anticipated strength of our first half results and taking into account a range of outcomes, we now expect total company adjusted EBITDA to approximate $1.29 billion when excluding foreign exchange, an increase of approximately $40 million from the guidance we provided in February. Within this total company outlook, we see the following relative to the guidance provided in February: Subsea revenue and EBITDA margins, both trending toward the upper half of the guidance ranges. Both revenue and EBITDA margin for Surface Technologies, as well as corporate expense, remain on track for the midpoint of their respective guidance ranges. Lastly, I want to discuss our current view of our capital structure. In March, we received an upgrade from Standard & Poor's to investment grade. This upgrade serves as a significant milestone for the company and reflects the tremendous efforts by the entire organization to materially deleverage the balance sheet and achieve investment-grade metrics. With this update, we are also revising our target capital structure to approximately $800 million of cash and $800 million of debt, together amounting to zero net debt. This is a $500 million reduction versus our prior target and a level we can achieve over time as scheduled debt maturities come due. Importantly, we believe this capital structure provides us with the flexibility to manage our operations and fund our capital needs, while also delivering on our commitment to shareholder distributions. Operator, you may now open the line for questions. The floor is now open for your questions. To ask a question at this time, simply press the star followed by the number one on your telephone keypad. We ask that you please limit yourself to one question and one follow-up question. We'll now take a moment to compile our roster. Our first question comes from the line of Arun Jayaram with J.P. Morgan Securities. Please go ahead. Good morning. Doug, I wanted to see if you could provide more details on Northern Endurance. What do you think drove your success on the projects? Maybe more details on the scope and perhaps what technologies is TechnipFMC providing in terms of the CCS nature of that project. Thank you, Arun, and good morning. Look, this was, as stated in my prepared remarks, a major milestone for our company, but also for the industry. This will be the first application of an all-electric production system. We are extremely, extremely proud to have been selected. There was a very rigorous technical qualification required to be able to be considered and to receive the award, and we're pleased that we came out on top of that qualification. Think of it as everything from the shore to the seafloor. We call it the Integrated Carbon Transportation System. We have a specific CO2 2.0 tree, so part of our 2.0 family, we have developed a configure-to-order CO2 injection tree. It looks simplified compared to a traditional oil and gas tree, but it's actually very technical, particularly when it comes to the sealing surfaces, because of the number of cycles that you will open and close, or what is called a cycle. The cycling of a valve in a CO2 injection tree is far, far greater than what you would do in a typical oil and gas development. So a higher technical standard. We were extremely pleased to be selected for that, and we have that entire scope. And what's really interesting about it is the distance that is being traversed is over 145 kilometers, and there will be nothing floating on top of the water. In other words, we've taken it all subsea, much like we did on the CCS project in Brazil, on the HISEP project. It is, it is just a major, major milestone, where we are really driving the CCS market by enabling the seafloor to be a key component of these projects. Great, Doug. And I wanted to see if you could maybe comment, and in your prepared remarks, you talked about some new technologies that you're using to unlock opportunities in more mature basins. I was wondering if you could maybe expand upon that and maybe comment on what you see in some of the, you know, more mature basins. I know one of your peers talked about anticipating maybe an improvement in West Africa starting next year, but maybe if you could elaborate on that. Sure. So there's just the, I would call it, the traditional projects that are likely to be driven forward in mature basins, given the project economics, by doing it with an integrated, you know, with an integrated approach, or what we call, you know, iEPCI, along with our 2.0 family, we can help unlock the economic value of those projects. But specifically, what I was referring to was in a mature basin, there's really two opportunities, is to find a different producing horizon. In the, in the case of the Paleogene, it's a deeper horizon, in the Gulf of Mexico. Or it could just be a further step out, from the host facility. And, and, and so what are the technologies that are the key enablers? To get to the Paleogene, it's 20K, and to have a full 20K production system, fully qualified, supported by the regulators, as well as our clients, you know, major achievement. As noted, this is our third project. This is the first integrated 20K project to be awarded, and as alluded to in the script, we expect more to come, in the future. When you look at the further step-outs in a mature basin, that will be enabled by all-electric. So this will be the primary application in the traditional energy or the oil and gas environment when it comes to the all-electric production systems. Again, enabling a much greater distance, up to three to four times further than you can do via using hydraulic controls, to reach back to an existing host facility. So the two key technology enablers, in this case, being 20K and the all-electric. In the case of HISEP, as we talked about in the first quarter, it was advanced CO2 separation, subsea separation technology, where we are separating and then reinjecting all on the seafloor. Great. Thanks a lot, Doug. Our next question comes from a line of James West with Evercore ISI. Please go ahead. Hey, good morning, guys. Good morning, James. How are you? I'm doing all right, Doug. How are you? Good, thank you. Actually, I saw your results, so I know how you're doing. You're doing well. Thank you. So I wanted to start a little bit bigger picture, and something we've talked about a bit in the past. You know, with the backlog that you have now, all of these iEPCI contracts coming through, how are you feeling about capacity, and are you starting to really leverage into some of these, you know, joint ventures and partnerships to add to that capacity to make sure you can deliver on all this backlog? James, a timely question. I would expect that you will see us utilize the support that we have within our ecosystem to be able to continue to grow and expand the EPCI market. And just for those that are not as familiar with, you know, the terminology, you know, ecosystem, you know, we made a decision years ago that we would restructure the way that, you know, the subsea industry operated, both from the integrated projects, but also from the way that we would drive higher asset utilization and drive-through cycle returns to a standard that was not only higher than in the past, but sustainable. And the way we would do that was to work well with others. And that's the personality of our company. You know, we're not a big monster. We work well with people. We have a very deep relationships, and they're all trust-based, and we put a lot of time and effort into that. So what that's allowed us to do was to go out to other vessel operators, introduce them to the EPCI concept, and as the EPCI market continues to grow and become a very significant portion of the total projects that are being awarded today, providing access to our partners to work alongside us on those projects, and deliver integrated projects. So that's what allows us to, if you will, expand beyond theoretical capacity, in the installation portion of the projects. But there's also the manufacturing side of the projects. And this is the, you know, a significant benefit, and I think one that's not been fully understood, but as you see it showing up in our financial results now, of the ability to be able to get leverage by using Subsea 2.0 configure to order. It runs through our plant at approximately double the cadence or half the time as a traditional 1.0, which is what the rest of the industry is building today. So they have to get additional capacity, either through consolidation or by expanding their capital budgets and building plant, whereas we've invested in the technology, and the technology, and then the system of going from an engineering to order to a configure to order, allows us to have that additional cadence through the plant. So again, allowing us to expand far beyond the traditional theoretical capacity. So, look, we monitor the situation very closely. We're very open. We share it with our clients. You know, we're having very long-term discussions, you know, well beyond the time period that we would traditionally be having discussions. And they have the confidence to have those discussions with us because of this new operating model, and they see that we, you know, they understand that we are doing things that will allow us to have the capacity to continue to expand and deliver and support their projects. Okay, got it. Very helpful, Doug. And then I thought some of the, you know, first-time awards, particularly on the carbon capture side, were fascinating. Could you maybe expand on this use of the seafloor for CCS? And was this, you know, contemplated initially as we targeted these projects? And if so, are, you know, additional offshore projects all targeting that? And then is the technology? Are you using kind of existing technology, or is this new novel technology? Both great questions. So look, we've been working on this for quite some time. And you know, James, as you know, we kind of, we look at any challenge from the seafloor up. Right. I think we might be the only company that really takes that approach because, you know, most companies, and quite frankly, most developers kind of think about, you know, onshore. And then if they go offshore, they want to have, you know, some sort of fixed bottom, like, you know, a monopile or something that that is touching the seafloor. Or if they go further offshore, they want to have some sort of a floating structure. We fundamentally believe the right way to do it is to eliminate the greenhouse footprint associated with those structures, is to put everything on the seafloor. But it takes very advanced technology, material science, automation, and controls that, quite frankly, there's very few places in the industry, but beyond the industry, you know, in academia, et cetera, that that really exists today. You know, we're proud that's where we operate. You know, we're putting things one to two miles deep in the water on the seafloor, designed to last for, you know, 25 to 35-year life, with all advanced automation, robotics, and controls, that, quite frankly, are, you know, challenge anything that's being done, you know, in the industry or beyond the industry today. So, when we look at a challenge like CCS, sure, we're, you know, we can be involved in a terrestrial project and happy to be involved in those projects. But fundamentally, you know, we believe that the safest and best place to store the CO2 will be in saline or abandoned aquifer or abandoned depleted reservoirs, far offshore. Right. They exist. They're well known. You can then transport from shore all the way out to those, into those, injection fields, all subsea, without having any sort of a floating infrastructure, as being demonstrated in the Northern Endurance Partnership Project, as we described. From a technology point of view, you know, it is important to note, you know, there are people that believe you can just reverse the flow and use existing oil and gas infrastructure. That's not, that's not true. It is much more of a technical challenge than that would make one believe. I talked a little bit about the tree and the tree design and the valves on the tree, as I explained. It also comes down to the control and automation and also the monitoring that's required on these projects. So, we have developed an entire, what we, again, call an Integrated Carbon Transportation System that allows us to take it, you know, basically from the host facility to an injection point. We would see, you know, we definitely see the trend, and not just in CCS, but also in other forms of energy and new energies that, you know, are really for them to reach their fullest potential to achieve the scale that is required, we see this going offshore, and that is certainly the trend and one that we are helping to enable, and we're proud to do so. Got it. Thanks, Doug. Our next question comes from the line of Luke Lemoine with Piper Sandler. Please go ahead. Hey, good morning, Doug. You recapped the merits of an all-electric subsea already, and you had the first announcement with Northern Endurance for CCS. Luke, we. And maybe. You dropped off, Luke. If you don't mind repeating the question, you dropped off, Luke. Yeah, sure. Just talking about, you know, the first all-electric system for, you know, Northern Endurance for CCS. You know, when you kind of look at oil and gas, when can we start seeing the uptake for all-electric? And when you're speaking with customers, you know, what are the pinch points, if there are any, when you're chatting with them? Sure. Thank you, Luke. Look, oil and gas is happening in parallel to the CCS opportunity, so you will see oil and gas opportunities using all-electric, you know, full field development. And I stress full field because, you know, keep in mind, we've been using electric actuation for many years, and we have over 600 all, you know, electric actuators installed on subsea equipment, you know, around the world. So that part of it is not novel. But to go to a fully electric system, which would include an electric subsurface safety valve, would be unique. And that's a partnership for us that we're working together with Halliburton to enable an all-electric subsea field development. But again, there's, you know, there's commercial activity going on in parallel. So, you know, you will see more in that area also. I would stress, though, in the area of oil and gas, that, you know, I see the bigger opportunities in the tiebacks. Why is that? Look, an all-electric tree is more expensive than a hydraulically, electro-hydraulically operated tree for all the right reasons. Now, when you look at it from a tieback point of view, those economics dissipate very quickly because in a long-distance tieback, the umbilical and the cost of the umbilical across that very long distance to be able to use hydraulic actuation would either be limiting, it would not be possible, or it would be very costly. But when you look at it on a unit cost versus a unit cost, an all-electric tree is more expensive. So therefore, in a greenfield development, I think those opportunities will be there. And, but the big market, and, and I stress, it will be a significant market, will be in the area of brownfield. We've talked about it before. If you look around the world at all the floating production assets that are out there today, FPSOs, FPUs, they're producing at between 60%-70% of nameplate capacity. All-electric brownfield tiebacks will allow them to be able to bring that back up to near nameplate capacity without any significant capital cost. And we've gotten the cycle time now on those brownfield projects down to such a level, slightly over one year, that it makes the economics very, very compelling. Our next question comes from the line of Guillaume Delaby with Bernstein. Please go ahead. Yes. Good morning, Doug. Good morning, Alf. Maybe a quick question regarding your new capital allocation policy. I'm not sure we can call it that way. So is it essentially resulting from, I would say, a better financial outlook? Or is there also some kind of, underlying, I would say, strategic thinking behind it? So maybe if you can elaborate a little bit on that. And an associated question, maybe I know it's time for capital discipline, but are you still considering or do you may consider to do some small targeted acquisition again in the coming quarters? Thank you. So let me start with the second part, Guillaume, and thank you for the questions. Look, we have and will continue to do small targeted acquisitions, but in most cases, we're taking small investments in early startups. Often it doesn't cost any capital because we're using human capital. The greatest currency we have in our company today is our subsea engineering. It is very unique to our company, and we have, by far, the most, you know, significant and most experienced and talented workforce. So often we can trade, if you will, subsea engineering hours to a company who's trying to tackle this challenge of: How do I go from being a terrestrial developer to being an offshore developer? Things change quite a bit. And, we have that knowledge, particularly when it comes to dynamic design, and I won't get into the details of that, but, you know, that's a major component, and then also, obviously, putting things onto the seafloor. I'm gonna have Alf weigh in on the first part of your comment, but I do wanna comment, you know, Guillaume, there were two major, messages that Alf delivered earlier. One, we were upgraded by S&P, and two, we are targeting net zero, in terms of our net debt. So two major, two major milestones, but I'll pass it over to Alf. Yeah, Doug, thank you, and maybe just to build on that. So today, we have a gross debt of just above $1 billion and a net debt of $327 million. And we have previously stated that we will operate this company on $800 million of cash. And further, as Doug said, I honestly believe that the net debt neutral position is a good target for us, and it would imply that we would reduce debt by a little more than $200 million from the current $1 billion level. And so this is, call it, an intermediate-term target and not necessarily where we need to be immediately. We certainly have debt that is gonna mature over the next two years that will take us there naturally. I will also emphasize that, you know, given our business outlook and the strong cash generation we see ahead, we continue to believe that share repurchases remains one of our best uses of funds, and we demonstrated that by distributing the majority of the Measurement Solutions proceeds here in the first quarter. But we also remain committed to achieving investment grade. As Doug said, we achieved an upgrade to investment grade from S&P now just in March. Overall, when you think about it longer term and strategically, and maybe that's what you're asking, with expected growth in EBITDA and with the debt keep on coming down from current levels, clearly expect to be below 1x gross debt to EBITDA leverage ratio as we go forward. Okay, very useful. I hand it over. Thank you, Alf. Our next question comes from the line of Marc Bianchi with TD Cowen. Please go ahead. Hi, thank you. I wanted to ask about sort of your scope opportunity on large projects. I'm looking at the Whiptail award and the Uaru earlier. I think you had expected them to be over $1 billion of inbound, and they ended up being $500 million-$1 billion. I suspect what might be going on there is some of the scope that you anticipated to get didn't materialize for you, it went to competitors. But could you maybe address that? And then talk about for your direct awards, sort of what scope you're getting right now versus maybe what your opportunity could be over time. Thanks, Mark. Appreciate it. And look, that's an important question. If it's on your mind, then we need to clarify it. So I appreciate you giving us the opportunity to clarify it. The Subsea Opportunity List that we publish every quarter is published from an industry perspective. You know, think of it as the rig count, if you will. So we're trying to demonstrate, to give people the opportunity to be able to see the opportunity set that exists within the subsea industry. Therefore, when we put that out, that's not what we expect or what we anticipate. It's these are tenders. These are projects that are being tendered by our clients, and the full scope of that is reflected in the value of those awards, or in what we place as the value, if you will. We use purple, blue, and red on our charts. So hopefully, that clarifies, you know, this is just what the company happens to be tendering. We may or may not be targeting the full scope of the project. In many cases, we are. What's important also to understand is that is a subset of the opportunity list for TechnipFMC. Now, that is the full opportunity set for the competition. But for TechnipFMC, because we are an integrated company, because we have iEPCI, because we do integrated iFEED, iFEED studies, we have the ability to enter into an exclusive, proprietary, integrated iFEED study that, upon completion, assuming we achieve the economical hurdle rate for the project and the project receives FID, that project, that project is then direct awarded to our company. Those aren't on the Subsea Opportunity List. Occasionally, one might show up on there just because it's such a well-known project. We need to put it out there. But because these are direct awards and proprietary to us, they're not on that opportunity list. So we have a second opportunity list that we look at every day, and that's really what drives the performance of our company and, quite frankly, the outperformance and why our inbound numbers often surprise to the upside. So just to give you a little bit of an idea of which, you know, there's really two lists. We're looking at one, the world's looking at the other. We may not be tendering some of the projects, by the way, on the Subsea Opportunity List, because we may not think that they're projects that, you know, we can contribute the greatest value to, meaning integrated or Subsea 2.0 or whatever it may be, or we may be concerned about, you know, something about the projects. We, we may or may not tender those as well. As far as the scope, I think you know, we are, you know, we have the most comprehensive. We can do a, an entire, subsea project. We don't have to bring in a third party or buy a third party, you know, key components. We've talked about it before, you know, the ability to be able to have the entire SPS, the entire SURF, both products and installation capability, you know, makes us and position us—and positions us uniquely. Okay. Thanks for that, Doug. I'll turn it back. Our next question comes from the line of Kurt Hallead with Benchmark. Please go ahead. Hey, good morning, Doug. Good morning, everybody. Morning, Kurt. Maybe, hey, maybe just a quick follow-up, you know, in, with respect to, to Mark's question, right? So again, you know, in the most recent past, you guys have given, you know, some of your outlook regarding, you know, what you would anticipate your subsea order book to look like over the course of the next couple of years. That wasn't explicitly referenced in this call. However, you know, given the dynamics at play, where you, you know, talk about quality over quantity, and then you talk about new technologies unlocking new business opportunities, I was wondering if you might be able to give us some update on how that—on how the order outlook has changed or, you know, if it has changed at all. Again, Kurt, you know, much like Mark, thank you for clarifying, because, you know, we do our best to communicate effectively, but you learn, you learn as well. So the fact that we did not mention that we have a target of $30 billion of orders for three years through 2025, or that we remain very confident in achieving our 2024 guidance of approaching $10 billion of orders, us not saying it, we thought was a strong message that we're very confident. But let me be very clear, we remain very, very confident. In terms of the, in terms of the FEED activity, in terms of the tendering activity, and in terms of the, I would say, very mature, meaning late stage, pre-FID conversations that I'm having with clients today, and I'm not complaining about it, Mark, but I'm very, very busy. Kurt, sorry. That's okay. That's all right. All good. All right, that's, yeah, that's it for me. Thanks for clarifying. Appreciate it. Our next question comes from the line of Scott Gruber with Citigroup. Please go ahead. Yes, good morning. Morning, Scott. I got one for Alf. You know, with the profitability of the business improving, the tax rate should trend toward a more normalized level over time, and we have the guidance, you know, for this year. How should we think about the evolution of the tax rate in 2025 and 2026? You know, where, where, where could that fall to in the years ahead? Oh, so thanks for the question on the taxes here. So first of all, maybe just point out, if you look at the effective tax rate for the quarter, this, there is a little bit of a timing effect of it being a little bit lower than normal in this quarter. So first of all, we stand behind our guidance of $280 million-$290 million for 2024. And if you consider the growth in EBITDA, et cetera, that we are projecting, I'd say that the, this is implying a roughly 35% effective tax rate for the year with our current earnings mix as planned. As we talked about a little bit before, we are targeting a normalized tax rate of 30%, and I would continue to build on that or model on that if you're looking for the out years. It largely will come from a combination of earnings mix and some other utilization of tax opportunities that we couldn't take advantage of in the past. So overall, we remain confident to drive towards a 30% normalized tax rate. How long do you think it would take to get there? Is that something that's possible in 2025 or more 2026? I mean, you're in the right ballpark of, you know, somewhere in that between those two years. Yeah. Okay. Okay, that's it for me. Thank you. Our next question comes from the line of Doug Becker with Capital One. Please go ahead. Thank you. Doug, you previously mentioned that all-electric subsea production systems could result in incremental tieback opportunities of $8 billion through 2030. Was just hoping you could frame maybe a realistic, realistic or risked opportunity as you see it today for FTI? Yeah, thanks, Doug. Yeah, that number is probably a little stale, actually, at this point. I would say there's upside to that number in terms of, you know, we put that out in, I think, 2021. Clearly, all-electric and the adoption and qualification of all-electric is now. We've pretty much covered our entire client base, and, you know, that takes some time. It's, you know, obviously, it's developing the technology, but then qualifying it and then getting your customers, you know, aligned. In terms of, I don't have a hard set, you know, year by year, kind of how I see that developing yet. It might still be a little bit early, but obviously, getting the first award was key, that being in the CCS environment, not in the brownfield tieback environment. But as I said, things are being bid in parallel today between CCS and traditional, you know, energy. So, there'll be more to come. But look, Doug, I remain very confident, and this one, I'll be honest, this one's a little bit of a no-brainer. You know, I, you know, if you're, if you're sitting with an existing host facility that's aging every day, that you can get some additional, you know, hydrocarbon to flow through and obviously improve their, you know, the financial results and, you know, leverage the cost of that capital investment that you may have made many years ago, it just makes sense. So we're kind of in a unique position. We have a lot of the infrastructure, you know, over 50% of the world's infrastructure on the sea floor. So we're in a unique position to really try to help to kind of marry up somebody that has a, what would be called a stranded asset, simply meaning it was too far away from a host facility, to be able to be economically produced and could not support its own host facility because of the CapEx required to do so, to be able to marry that up with a, somebody that has a production asset. And that's certainly what we're doing today in the conversations that we're having. No, that certainly sounds encouraging. Is it reasonable to expect an all-electric award on the oil and gas side this year or more of a 2025 award? You know, we like to think about things in 24-month time frames just to be a little bit conservative, but you could see something on the shorter end of that for an all-electric oil and gas award or a project, you know, being FID. I do think you could see that. Again, up to our customers when they FID, but if I just think about the commercial discussions and the maturity of those discussions, and that's what I meant by, you know, in parallel, meaning, you know, it, it wouldn't be too far out. Got it. And then just a quick one, Alf. The free cash flow loss was narrower than at least I expected to my consensus expected, in the context that Subsea is toward the upper half of the guidance range. For free cash flow, is that trending toward the upper half or midpoints still the best place to anchor? So, first of all, free cash flow, you're right, we had a strong first quarter for being us at least. You know, the net outflow represents really, it's of $179 million, really represents a solid start for the year for us. And because it is typically our seasonally most weak quarter that we have, and also point out that, you know, we did have the $56 million payment towards a legal settlement that affected the quarter. So overall, we feel really good about where we are, and I expect, obviously, this to build during the year. We typically trend up during the year, and you will see the majority of the cash flow generation in the second half of the year. And clearly, as we grow EBITDA. In particular, in Subsea, we expect to see a little bit of additional conversion of free cash flow from EBITDA. So, we typically use the 50% ratio is where we operationally sit today. So if you want to use that as an approximation, but we're not ready to officially take up free cash flow. There is always working capital dynamics and other things that lead to the end of the year. Again, if you look at our business profile, the fourth quarter would still be the big quarter to determine the overall cash flow for the year. Understood. Thank you. Our next question comes from the line of Daniel Thomson with Exane BNP Paribas. Please go ahead. Hi, good morning. I had a question on HISEP. I mean, now that the contract has been awarded, and clearly, your part of the technology has been qualified with Petrobras, can you talk about the sort of conversations you're having with that client around using the technology in other fields? You know, anything specific to flag? And have you had any interest from other clients in Brazil or internationally about using a similar technology? Thanks. Thank you, and good afternoon, Daniel. The answer is yes and yes, is the short answer, but I'll give you a little bit of color around it. Clearly, Petrobras is approaching this as a design one, build many. Obviously, you know, a benefit of being part of this first award. But they clearly see this as an opportunity to reduce the greenhouse gas intensity, first and foremost, but also in the case of the Mero 3 project, because it's existing in an existing field or a brownfield, if you will. It also allows to de-bottleneck and increase production at the same time. But, you know, I don't wanna speak too much on behalf of my clients, but I can assure you, you know, Petrobras has stated and very much see this technology as one that they are going to use multiple times. An interest from other clients, first of all, there are partners in the Mero 3 project, a very well-known, large, you know, world-class companies as well, along with Petrobras. So they've obviously been intimately involved and are supportive of the technology and obviously supportive of the project. They provided the partner approval for the FID. So you know, we have those who are quite intimately included. And I'll tell you, just recently, I traveled actually with a client to Brazil because they wanted to learn more about it. Now they won't be using it in Brazil. They would be using this type of technology outside of Brazil, but they were so interested, and, you know, I was more than happy to participate in that visit with them. And, with the support of Petrobras, you know, we were able to share with them some of the good things that we're doing and what we've done in terms of the development of the technology. So, again, short answer, yes and yes. Thanks, Doug. And if I can squeeze in a follow-up, this time on the surface business, you know, in Saudi Arabia after the Aramco MSC 12 announcement. I mean, given the incremental spending is going onshore, you know, unconventional gas from an offshore market where you don't compete, I mean, this seems like an incremental positive for your particular mix in the Middle East. But can you confirm your sort of readiness to respond to that incremental onshore demand for surface equipment? And how does the opportunity, you know, in Saudi, compare to your expectations for demand before the announcement from Aramco? Thanks. Sure. And Daniel, maybe just to clarify, for everyone, in Saudi Arabia, that business falls under our Surface Technologies business. And when we, you know, when we think about, you know, well heads and trees, if they don't get wet, i.e., if they don't go below the water surface, then that falls under our surface business. So our business in Saudi Arabia is primarily an onshore business. That's what we do. And actually, you know, we're very, very good at it. So the reduction in the, you know, the jackup market and the reduction in some of the offshore activity, it does affect us because, again, they typically are produced from a production platform, so it's a dry tree. But the number of wells versus the number for the CapEx dollar spent, versus the number of wells that can be drilled for the same amount of CapEx on land, the latter is obviously far greater. So from our, from our perspective, I'm only answering from our perspective, you know, selfishly, a shift to land CapEx from offshore CapEx is very favorable to our company. Think of it as simple as we sell product, you know, that allows a well to be, you know, safely and environmentally, appropriately, you know, produced. And so we get, we get paid by the well bore, if you will, and that's what matters. In addition, gas is important to us. You know, our revenue per unit sold is higher in gas than it is in oil, so the shift to gas is favorable. In unconventional gas, we are able to provide additional products around the fracturing and the stimulation side of it, as well. So it expands our, let's say, revenue per well. You know, that's how the market works for us. Now, more importantly, and you know, as you've been following the company, you know, we decided to make a strategic investment in the Kingdom to bring manufacturing capacity from Asia to the Kingdom. We continue to ramp up our new facility, and that has gone very successfully. We've not yet reached its fullest potential, and we anticipate, you know, further improvement in the second half of the year. So, Saudi Aramco remains very important to us. The Kingdom is a key contributor in our Surface International business, and we're very well positioned, and quite frankly, some of the announcements have been favorable from our perspective. That's helpful. Thanks, Doug. Our next question comes from the line of Saurabh Pant with Bank of America. Please go ahead. Hi, good morning, Doug. Good morning. Doug, maybe let's spend a little time on the quality of the backlog that you've been talking about on the Subsea side, right? I think it's visible in the results you are delivering, the margins you are delivering, but also the new technology awards that you're winning. If you can spend a moment on a phrase you mentioned in your press release, Doug, the heightened focus on project selectivity. How are you doing that? What's the focus? Is it more about terms and conditions, or are we talking about just integrated projects versus the standalone projects? Sure. Great question. We talk about it every day, as we look at the different opportunities that we have in front of us. Look, it's a combination of all of the above. But let's start with, you know, the main thing that really drives, what we would, you know, deem as quality, because we believe it, and we've demonstrated it's best for the project in terms of shortening cycle time, accelerating time to first production, and it greatly simplifies our execution model, is the Subsea 2.0 configure to order. So clearly, the higher the 2.0 orders, the higher the quality of the backlog. And that allows us to go from engineer to order to configure to order. As I've talked about before on this call, that allows us to eliminate nine months of engineering. So if we take a 1.0 order, which is how the rest of the industry is operating, they have to spend 9 months, or we would have to spend 9 months doing detailed engineering because you're building a first article. It's never been built before. So you have to go through that before you place a single purchase order. With the Subsea 2.0 configure to order platform, and again, you can't just say, I have it. You have to have a platform. You have to have critical scale. That allows you to not only simplify the internal, as I talked about, you know, putting twice the volume through our existing manufacturing footprint, but it also allows us to simplify and to secure a much more reliable and competent partners in our supply chain. So it's really a combination of the two that lead to the quality. In addition to that, an integrated project, we just have many more levers. You know, we take on the full scope. We have the ability to be able to schedule activity that best works for us. And that's why it was so important to consummate the relationship and create TechnipFMC, because very difficult to do when you're not a single entity with a single set of financial reporting and a single set of objectives, because then you have underlying competing, competing interests. So we have that. And then on top of that, sure, the terms and conditions of the contracts are important. Our customers understand that. We've talked in the past about, you know, what we've done to ensure that, you know, the things are being shared, you know, in the most appropriate way. And, for instance, you know, when it comes to inflation, we put in place several parameters that allow us to be more confident that we're not going to be surprised on that side. So, you know, all in all, it's a combination of the three, but it's very clear for us where our focus is. And as you hear us announce these iEPCI and iEPCI 2.0 and 2.0 awards, it's just, it's just very, very favorable to the future and to the surety of our execution. Thank you. Look, no, Doug, that's very helpful. Just a very quick follow-up, Doug. I know you are $30 billion in three-year order outlook for Subsea. That does not include any of the frontier basins. But the news flow, especially from Namibia, has been particularly positive. Can you share any updated thoughts on your outlook in terms of these frontier basins? I know it's beyond 25, but any updated thoughts, Doug? Sure. Lots of discussion, lots of activity. We're using our playbook from Guyana and Mozambique, both of which, you know, we were the first mover. We understand how to do this in these emerging markets. We're executing the same playbook in the other emerging markets. And I would say net-net, from, you know, most recently, the indications from our clients that they've, you know, that they have stated publicly, I'm not saying anything that's not public, I would say is more favorable, and, you know, trending in a very favorable fashion. So we look forward to the contribution from those emerging markets, in the latter part of the decade. Right. Okay, perfect. No, Doug, thank you. I'll turn it back. Our last question will come from the line of Bertrand Hodee with Kepler Cheuvreux. Please go ahead. Yes. Hello, Doug. I have probably a follow-up on Namibia. Based on your earlier discussion, and clearly no need to mention any operator name here, but conceptually, from your understanding, do you believe it will require specific technologies and/or the iEPCI model or Subsea 2.0 will be well suited for future Namibia development? Thank you, Bertrand. Look, speaking of Namibia in particular, the one well-known challenge will be the water depth. So these are very deep, you know, it, it's very deep, within the operating parameters of 2.0, so no concern there. And certainly we believe the iEPCI model, as we've demonstrated in other emerging markets, is clearly a very favorable model and one that we would expect would unlock the greatest value and accelerate time to first oil for our customers, which drives their project economics. So iEPCI 2.0, but working very closely with our clients. So they're obviously learning as they're doing their extended well tests in terms of, you know, the producibility of the reservoirs, compartmentalization, the geochemistry. So there's things we're learning along the way, but we are actively engaged with them to ensure that we'll be ready to provide them world-class subsea support. Thank you. I would now like to turn the call over to Matt Seinsheimer for closing remarks. This concludes our fourth quarter conference call. A replay of the call will be available on our website beginning at approximately 8 P.M. Greenwich Mean Time today. If you have any further questions, please feel free to contact any member of the investor relations team. Thanks for joining us. You may now end the call. This concludes today's call. You may now disconnect.