Thank you for standing by, and welcome to the TechnipFMC 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 seafloor. During the quarter, we were also awarded the first iEPCI to utilize a 20,000 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 20,000 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 20,000 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 U.K.'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 kilometers 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 2 years. And 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 towards 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 the 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.

Our first question comes from Arun Jayaram with JPMorgan Securities.

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 FTI providing in terms of the CCS nature of that project?

Thank you Arun. 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 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. I think of it as everything from the shore to the seafloor. We call it the integrated carbon transportation system. We have a specific CO2.0 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 times that you would 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. There's 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 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 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 can maybe expand upon that and maybe comment on what you see in some of the 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, traditional projects that are likely to be driven forward in mature basins given the project economics by doing it with an integrated approach, what we call 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 2 opportunities is to find a different producing horizon. And 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 so what are the technologies that are the key enablers? To get to the Paleogene, it's 20,000 and to have a full 20,000 production system fully qualified, supported by the regulators as well as our clients, major achievement. As noted, this is our third project. This is the first integrated 20,000 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 3 to 4 times further than you can do via using hydraulic controls to reach back to an existing host facility. So the 2 key technology enablers in this case being 20,000, and the all-electric. In the case of HISEP, as we talked about in the first quarter, it was advanced CO2 subsea separation technology, where we are separating and then reinjecting all on the seafloor.

Actually, I saw your results. I know how you're doing. You're doing well. I wanted to start a little bit bigger picture. It's something we've talked about a bit in the past. 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 joint ventures and partnerships to add to that capacity to make sure you can deliver on all those backlogs?

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 iEPCI market. And just for those that are not as familiar with the terminology, ecosystem, we made a decision years ago that we would restructure the way that 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. We're not a big monster. We work well with people. We have 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 iEPCI concept. And as the iEPCI 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 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, we're having very long-term discussions 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 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 first-time awards, particularly in the carbon capture side are fascinating. Could you maybe expand on this use of the seafloor for CCS? And was this contemplated initially as we targeted these projects? And if so, are additional offshore projects all targeting that? And then is it 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. Anyhow James, as you know, we look at any challenge from the seafloor up. And I think we might be the only company that really takes that approach because most companies and quite frankly, most developers think about onshore. And then if they go offshore, they want to have some sort of fixed bottom like a monopile or something 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 are very few places in the industry. But beyond the industry, in academia, et cetera, that really exists today. And we're proud that that's where we operate. We're putting things 1 to 2 miles deep in the water on the seafloor, designed to last for 25 to 35 years with all advanced automation, robotics and controls that, quite frankly, challenge anything that's being done in the industry or beyond the industry today. So when we look at a challenge like CCS, sure, we can be involved in a terrestrial project and happy to be involved in those projects. But fundamentally, we believe that the safest and best place to store the CO2 will be in saline or abandoned depleted reservoirs for offshore. And they exist. They're well known. You can then transport from shore all the way into those injection fields all subsea without having any sort of a floating infrastructure being demonstrated in the Northern Endurance partnership project, as we described. From a technology point of view, it is important to note there are people that believe you can just reverse the flow and use existing oil and gas infrastructure, 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, 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, again, call an integrated carbon transportation system that allows us to take it basically from the host facility to an injection point. And we definitely see the trend and not just in CCS, but also in other forms of energy. And new energies that 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.

Yes, sure. Just talking about the first all electric system for Northern Endurance for CCS, when you kind of look at oil and gas, when can we start to see any uptake for all-electric? And when you're speaking with customers, 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 full field development, and I stress full field because keep in mind, we've been using electric actuation for many years, and we have over 600 electric actuators installed on subsea equipment 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 commercial activity going on in parallel. So you will see more in that area also. I would stress, though, in the area of oil and gas that I see the bigger opportunities in the tiebacks. And why is that? Look, now an all-electric tree is more expensive than an electrohydraulically 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. But the big market, 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 today, FPSOs, FPSUs, they're producing at between 60% and 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 1 year that it makes the economics very, very compelling.

Yes. 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 acquisitions again in the coming quarters?

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 start-ups. Often, it doesn't cost any capital because we're using a few financial 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 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 that's a major component. And then also, obviously, putting things onto the sea floor. I'm going to have to weigh in on the first part of your comment. But I do want to comment, Guillaume, there were 2 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 2 major milestones, but I'll pass it over to Alf.

Yes, Doug, thank you. And maybe just to build on that. So today, so 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. And we certainly have debt that is going to mature over the next 2 years that will take us there naturally. I will also emphasize that 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. And as Doug said, we achieved an upgrade to investment grade from S&P now just in March. But 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 keeps on coming down from current levels, clearly expect to be below one time gross debt-to-EBITDA leverage ratio as we go forward.

I wanted to ask about your scope opportunity on large projects. And I'm looking at the Whiptail Award in the Yahoo earlier; I think you had expected them to be over $1 billion of inbound and they ended up being $500 million to $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 on 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?

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. 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, 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 we place the value, if you will, we use purple, blue and red on our chart. So hopefully, that clarifies 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 FEED studies, we have the ability to enter into an exclusive proprietary integrated FEED study that upon completion, assuming we achieve the economical hurdle rate, for the project and the project receives FID, 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 there's really 2 lists, we're looking at one, the world is 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 we can contribute the greatest value to, meaning integrated or Subsea 2.0 or whatever it may be or we may be concerned about something about the project. So we may or may not tender those as well. As far as the scope, I think you know we have the most comprehensive. We can do an entire subsea project. We don't have to bring in a third party or buy a third-party key components. We've talked about it before; the ability to be able to have the entire SPS, the entire SURF, both products and installation capability makes us and positions us uniquely.

Maybe just a quick follow-up with respect to Marc's question, right? So again, in the most recent past, you guys have given some of your outlook regarding 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, given the dynamics at play where you can 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 the order outlook has changed or if it has changed at all?

Again, Kurt, much like Marc, thank you for clarifying because we do our best to communicate effectively, but you learn as well. So the fact that we did not mention that we have a target of $30 billion of orders for 3 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 it was a strong message that we're very confident, but let me be very clear we remain very, very confident. In terms of the feed activity 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, Marc, but I'm very, very busy.

I got one for Alf. With the profitability of the business improving, the tax rate should trend towards a more normalized level over time. And we have the guidance for this year, how should we think about the evolution of the tax rate in '25 and '26, where could that fall through in the years ahead?

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, 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 to $290 million for 2024. And if you consider the growth in EBITDA, et cetera, that we are projecting, I'd say that 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.

And how long do you think it would take to get there? Is that something that's possible in '25 or in '26?

You're in the right ballpark of somewhere in that between those 2 years, yes.

Doug, you previously mentioned that all-electric subsea production systems could result in incremental tieback opportunities of $8 billion through 2030. I was just hoping you could frame maybe a realistic or risk opportunity as you see it today for FTI?

Yes, thanks, Doug. That figure is probably a bit outdated at this point. I believe there's potential for that number to grow since we mentioned it back in 2021. The adoption and qualification of all-electric systems is happening now, and we've largely reached our entire client base. This process takes time, as it involves developing the technology, qualifying it, and aligning with customers. I don’t have a precise annual forecast for how this will evolve, and it might still be a touch early to say. However, securing the first award was crucial, particularly within the CCS environment rather than the brownfield tieback space. Currently, we are seeing bids for both CCS and traditional energy happening simultaneously, so more developments are on the way. We remain very confident. Frankly, this is somewhat of a clear-cut situation. If you have an aging existing host facility that could benefit from an additional flow of hydrocarbons, thereby enhancing financial results and optimizing the investment you made years back, it makes perfect sense. We are uniquely positioned in this regard, with over 50% of the world’s infrastructure located on the seafloor. This puts us in an ideal spot to connect those with stranded assets—essentially, assets too distant from a production facility to be economically viable—with those who possess production assets. That's exactly what we are actively pursuing in our current discussions.

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?

We'd like to think about things in 24-month time frame 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 being FID. I do think you could see that. Again, up to our customers when the FID. But if I just think about the commercial discussions and the maturity of those discussions, and that's what I meant by in parallel, meaning it wouldn't be too far out.

First of all, regarding free cash flow, you're correct. We had a strong first quarter, especially for us, with the net outflow of 179 marking a solid start to the year. This is noteworthy since it's usually our seasonally weakest quarter. Additionally, we had a $56 million payment related to a legal settlement that impacted the quarter. Overall, we feel very positive about our position, and I expect this to improve throughout the year. Typically, our cash flow trends upward during the year, with the majority generated in the second half. As we grow EBITDA, particularly in Subsea, we also anticipate converting some free cash flow from EBITDA, and we typically operate with a 50% ratio as a guideline. However, we are not ready to officially project free cash flow yet, as there are always working capital dynamics and other factors to consider as we approach the end of the year. Looking at our business profile, the fourth quarter will be crucial in determining our overall cash flow for the year.

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 conversations you're having with that client around using the technology and other fields, anything specific to flag? And have you had any interest from other clients in Brazil or internationally about using a similar technology?

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, 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 in an existing field or a brownfield, if you will, it also allows to debottleneck and increase production at the same time. But I don't want to speak too much on behalf of my clients, but I can assure you, Petrobras has stated and very much see this technology as one that they are going to use multiple times. Interest from other clients. First of all, there were partners in the Mero 3 project, very well-known large world-class companies as well along with Petrobras. So they've obviously been intermittently involved and are supportive of the technology and obviously supportive of the project, they provided partner approval for the FID. So we have those who are quite intermittently 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 I was more than happy to participate in that visit with them. And with the support of Petrobras, 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. Operator, you may now turn the call over to Matt Seinsheimer for closing remarks.

This concludes our first 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.