TechnipFMC plc (FTI) Earnings Call Transcript & Summary

Yes. Good afternoon. We're on to the back nine of the 9th Annual JPMorgan Energy Conference. So thanks for everyone's support. My name is Arun Jayaram, I'm the OFS and E&P analyst at the firm. Delighted to continue our sessions with TechnipFMC, CEO, Doug Pferdehirt, really excited to talk about the story. And I think that I say this with -- I'm a critical eye, but I think really, Doug and his team have really transformed the Subsea business for the better. And I think some of -- they're benefiting from some of the fruits of their labor that they developed -- that they planted in 2016 and actually going back maybe a decade ago and really excited to host Doug. How are you today?

Well, I'm great, Arun. Thank you very much. Thank you to JPMorgan for having us. Good to know we're on the back nine. I tend to perform better on hole 10 after hitting the halfway house. If you've ever heard about my golf, you'll know I work hard. I don't golf very often. So glad to hear we're on the tenth hole anyway.

Well, I hope you're a better putter than Rory McIlroy. He got some challenges in 16 and 18, but anyways, we will get off the golf for a second. Doug, I was wondering if you could start with the company's core strategy and what you think is unique about your business model versus your peers.

Big question. I'll try to be brief. We don't have a lot of time here. We realized back in 2012, 2013, good times in the industry, as you all recall. But there was a dislocation, which was our numbers were great: inbound revenue, margin returns. Everything was really good. But when you looked at it from the -- at the project level, at a Subsea project level, they were actually deteriorating. Returns were deteriorating rapidly because projects were being delivered up to 1 year late and significantly over budget. So you kind of have to take one of 2 approaches, either you ignore that. That's your customer. For me, my customer is a Subsea project. Now there's a customer's name on top of it. But I think about my customer is that project. So my project is suffering, and I can ignore it and just keep doing what I'm doing. Or you've got to step back and say, am I part of the problem? Or could I be part of the solution? And that really led to us approaching it very differently. And to do that, we invested 4 years into a disruptive technology that allowed us to come out with a completely new technology platform that not only was disruptive, but also allowed us to experience a much different operating model. So we call that Subsea 2.0 is the technology platform, which drives configure to order in terms of our new operating model supported by the principles of Lean. Then we looked at the commercial model, and we said this isn't optimal. Now it's the way it's always been done. The client managed multiple different interfaces on a Subsea project. And they might split a project in the 14, 1-4, 14 different tendering packages. But when we looked at it, we said, why? Well, they felt they could manage the interfaces better. They maybe had individual experiences, whatever it may be. Well, there was a -- the major divider between the two was typically somebody manufactured the equipment or parts of the equipment if it was split multiple ways and somebody installed the equipment. But why should the customer sit in between? What value is really being added? Well, no one was filling that space, so the customer was required to fill that space. It was a void. It was the only way to get a project done. So we looked at it from end to end, from the early engineering all the way through the life of field of services of the Subsea project and said, what would it take to be able to provide that breadth of product, service and support. Well, it took the merger of Technip and FMC, creating TechnipFMC, which was the only single move on the chess board, which is very important to understand. It was the only single move on the chessboard that allowed us to put all of those attributes into one company. Now at the time, it was a fork in the road, but we weren't taking the path less traveled. We were taking the path that had never ever, ever been traveled before. There had never been an integrated project in Subsea, it simply didn't exist. The capability didn't exist. But we weren't reckless, we studied it for over a year on paper, doing front-end engineering designs for our clients, showing them the value of this integrated offering. Between the integrated offering and the new technology platform, we were able to demonstrate to our clients that we could deliver first hydrocarbon 9 to 12 months earlier with much greater certainty in terms of the project delivery. And that's what changed the game because, again, the client was the project. So we now address the issues that lie within the project that was leading to the deteriorating returns. We created something that wasn't just a one-off, that something that was sustainable. It was a new way of working with a new technology platform driven underlying and supporting a new commercial model. The result of that has been beyond even my high expectations. We're humbled by that. But it took a lot of risk and it took a lot of energy. I want to put a shout-out to my team. This simply wouldn't have been possible without the 22,000 women and men at the company who believed. It was easy not to believe. I would say most people were not necessarily supporting us at the beginning because it was so radical. But here we sit today, the integrated model has become the model of choice. About 1/3 of the market is now integrated. Over $20 billion in projects have gone the way of integration. Subsea 2.0, the disruptive technology, the new product platform now represents about 50% of our new orders. And how does this all manifest itself? How do you tell if you feel good, if you really know if you're winning? 70%, 7-0, 70% of our business is direct awarded to our company, never goes out to competitive tender. That means our clients understand the value, they trust us in the execution mode and they reward us with these direct awards.

Doug, I know you've taken inspiration for the evolution of your business model, Subsea 2.0, in companies outside of the oil and gas industry, including the automakers, Toyota. I was wondering if you could maybe highlight some of those learnings and how you've adapted that to FTI.

Thanks. So I'm sorry, I was getting on my -- I was getting a little emotional there. So yes, things were going well. But great companies don't get foolish, right? They don't look in the mirror and say, we're the best company. The minute you do that, you're deteriorating. So when we looked in the mirror, we said, what can we do better? And what we realized was that this: even though we had this new technology called Subsea 2.0, we really needed to drive the operating model to be much, much more efficient than it had been historically because remember, in subsea, you're building something first article every project. Every project has new specifications, requires significant amount of engineering, et cetera. How could we change that? Well, we worked with Toyota because of -- through the Lean Institute. This is a scientifically proven model, it's nothing we invented. And obviously, the auto industry figured it out a long time before we did. But we had to convince our clients that we had a configurable architecture, Subsea 2.0, that it met their needs. We had to qualify it with each of those clients. So the auto industry, we all feel like when we're ordering -- well, I won't speak for you, but I feel like when I'm ordering a vehicle that they're building it just for me. It's Doug's car, doesn't matter what manufacturer. It's Doug's and then it's -- I get in the car. Within the first few weeks of driving, one of my daughters points out, "Hey, dad, that looks just like your car," and then all my great aspiration goes away. Same idea, right? They made it look like they were building it for me because I had a series of drop-down menu options, but the reality of it is they were doing zero engineering at the time of order. When you order that vehicle, it goes straight into assembly and test. That's what we've done. That's how we've transformed Subsea. So no longer do we do 9 to 12 months of detailed engineering when we get an order, just to be able to place a purchase order, just to be able to place purchase order number one with the supply chain. Now when we get an order on a series of drop-down menus on an app from our customer, it goes straight into our manufacturing assembly and test. And these are all pre-engineered components. So we cut out that 9 to 12 months. Hence, our ability to be able to consistently deliver first oil, first production up to 1 year ahead of the norm, and that's really the success factor. So I can't say enough. The Lean Institute has been phenomenal. They've worked very well with us and we've learned a lot, and we continue to learn today.

All right. Let's shift gears, talk a little bit about Subsea. How would you characterize the offshore spending picture, including in your core deepwater markets, markets like the U.S. Gulf of Mexico, Brazil and West Africa?

Sure. Just focusing on those 3?

U.S. and North Sea.

Okay. Well, overall, the only word you could really use is robust. I spend a disproportional amount of my time, which is a good thing, by the way. I'm not -- we're not complaining. I spend a disproportional amount of my time right now in tender reviews, approvals, client discussions, et cetera, around new activity.

New activity.

So I would say it's extremely robust. Within those existing basins, there's always dynamics to each basin. Brazil has and continues to be very robust. The Gulf of Mexico, we're seeing kind of a resurgence and that's because of the Paleogene, which makes sense. You've got all the resources in the basin, you might as well go and see if there's anything deeper. It's not that -- it's kind of -- it kind of makes sense when you think about it. So they've got the leases. The infrastructure is there to support them, so they went, looked a little bit deeper and they've discovered the Paleogene, which looks to be very, very attractive. Four projects to date, more to follow. We just announced an iEPCI 20,000 PSI project for Shell on the Sparta project this first quarter. And when you look at the North Sea, there was some government support, some tax relief that was given. So we saw a significant amount of new projects being sanctioned towards the end of last year.

Okay. Let's talk about some of the emerging basins, Guyana, Suriname, Namibia, Mozambique. And what are some of the new emerging basins?

So okay, I was hoping you were going to go to [indiscernible]. So the fun part about what you just did was I remember when Guyana and Mozambique came along, what now, about 10 years ago and I said this is it. One of the reasons I've enjoyed this career is I love going to new countries. I like being immersed in new cultures. I've had some pretty interesting experiences that will come out in a Netflix miniseries. But I mean, sometimes they don't go exactly how you intended them to go, but they're all learning experiences and great people around the world. But I really thought and so I immersed myself actually in Mozambique and Guyana, spent a lot of time because I kind of thought this was my last rodeo, if you will. Both have been phenomenal, particularly Guyana. Honestly, it's a little bit hard to think of Guyana as an emerging basin, but it is. But it's because of the phenomenal success of ExxonMobil and their partners. I mean, what they have done is just phenomenal, both in terms of the cadence and the pace in which they've done it, but also how they're doing business in Guyana. It is the right way to do business. We're honored to be associated. We do all of the work in Guyana. So we're also very proud of that. And ExxonMobil after the first project, which was Liza Phase 1, which was a competitive tender, which we were awarded based upon their confidence in our ability to be able to meet an accelerated delivery schedule, every other project has been direct awarded to our company, which is -- says a lot. Mozambique started off strong with ENI and the FLNG and Coral South, and that project is producing gas today in the country and very important for the country. I certainly believe there will be more projects in Mozambique. There's obviously been some setbacks. There will -- we all know about them. But they're being monitored, the right steps are being taken and I feel quite confident that we'll see Mozambique -- a resurgence, if you will, in Mozambique. The next I'd go to -- and I'm not necessarily saying they're going to happen exactly in this order, but plus or minus. I'll probably go to Suriname next. TotalEnergies has talked a lot about their Block 58. And their expectation is to move forward with an FID in Block 58 this year. We certainly hope that's the case, and we would be honored to be, once again, a first mover in an emerging country to be if we were chosen to support TotalEnergies in Suriname and Mozambique, by the way. Then I would probably go -- then I think it's a little -- probably Namibia. I think there, you've got different operators who have very different personalities. Some are very, very analytical and they're really taking the time to really understand the reservoir and really derisk the reservoir before necessarily moving forward. And you have others who clearly want to just move as quickly as they can, right? And it all -- just a different philosophy. One is not right, one is not wrong. We're obviously working with all of the potential operators in Namibia right now. And we would, again, look forward to seeing Namibia grow its resources. Beyond that, I'll throw in one. I don't think you mentioned. Don't forget about Tanzania. The Tanzania reservoir is pretty much it's like the Perdido trend in the Gulf of Mexico, it's half in U.S. territorial waters, half in Mexican territorial waters. Very similar for the gas trends in Mozambique, it kind of spans the maritime border between Tanzania -- it's Northern Mozambique, Southern Tanzania. So could Mozambique move forward? It could. I'm not saying it will, but it could move forward. Obviously, South Africa with Namibia, Colombia is actually quite interesting. And Mexico as well, as I mentioned, they've got some good resource in the deepwater close to the U.S. territorial water. So what's interesting in all that is just there's a lot there. It's all more or less latter part of the decade or into 2030, which gives us unique visibility into the durability and duration of this cycle.

Doug, I wanted to ask you about how some of your technological innovation is leading to unique commercial opportunities. Maybe start with your all-electric subsea solution.

Sure. So a shout-out to Luana Duffe, who heads our New Energy business. She's here with me today. We had 2 big awards in the first quarter, one for the BP Northern Endurance partnership. We just call it BP NEP, that's in the North Sea. And this is simply taking carbon from an emitter onshore and disposing of it offshore permanently. By the way, that's the right answer. The right answer is offshore, far away in a very safe way. And that's the way that I think as you start to scale up in carbon capture storage, the storage is going to become more and more a social issue. And then thinking about that you're going to be storing it onshore, I think, is as limitations and to get to the scale that's required just needs to go offshore. BP NEP, this project is Northern Endurance Partnership is a great example of that. That's going 145 kilometers off the Teesside. So what we are doing is we're enabling that with an all-electric system. So this will be the industry's first all-electric subsea system. So we're very excited about that. Playing to the strengths right? So it's a CCS project, but we're playing to the strengths of our core business, which is subsea. The other project is the HISEP project in Brazil which, in some ways, is even more fascinating because, in this case, it's the first time ever that we are going to take and separate CO2 on the sea floor and reinject it. So that CO2 will never see the atmosphere as opposed to producing it to the top of the water column to an FPSO doing the gas treatment, reinjecting the CO2 back down into the reservoir. We're going to do all of this on the seabed. Look, it just makes sense. It allows -- it will allow the FPSO to produce more oil because it will have to be throttled back over time because of the amount of CO2. In essence, you're producing -- like in West Texas, you produce water. You don't produce oil, you produce water with a little bit of oil in it. And in this case, you're producing a lot of CO2 with a little bit of oil. Let's just keep the CO2 at the bottom of the ocean in a closed loop system, separated reinjected. We can do that as a dense gas, which is much more efficient than when we do it on the top of the FPSO, where we have to do it in the gassiest phase. So it's a much more efficient way to do it, but it also allows us to improve the overall economics and that's what was attractive to Petrobras. Both of those projects, interestingly enough, both the BP NEP and the North Sea CCS project and the CCS project for Brazil -- for Petrobras in Brazil called HISEP, are both being done with the iEPCI model. So we're showing that our iEPCI or that integrated model will also apply in the new energy space, not just in the oil and gas space.

Doug, I wanted to talk to you about your outlook for Subsea. You updated your outlook in February of 2023 for 2025. And that was a raise relative to your 2021 Investor Day. So your current 2025 outlook is for $8 billion of Subsea revenue and 18% margins. Just general thoughts on this outlook, confidence on achieving this because you did provide this -- it's a lofty guide when you provided it.

Well, thank you for pointing that out which is true. But look, we are very confident. I will say things have certainly continued to improve since February of 2023, so if you just look at kind of the overall activity and the market and such. So it's only gotten better. And look, we're very committed to achieving that aspiration. What I think is sometimes misunderstood in that is, well, if it's 2023 at the time and they're giving '25, then that must be as good as it gets because why else would you pick '25, you could have picked any year, you wanted, right? Please don't think that way. 2025 goes all the way back to a 2021 Analyst Day when, in 2021 -- first of all, thank you all for being here. Nobody was in the room in 2021, like nobody. Everybody believes Subsea was dead. I was told repeatedly in the one-on-one meetings that there will never ever, ever again be a Subsea project, "Doug, get over it. Go find a new career." Okay, fine. So instead of just talking about it, we wanted to put numbers to it. That's why we put the 2025 guidance back in 2021 because we saw this wave of offshore happening. You have to understand, we are in detailed intimate conversations with clients on every major subsea project going on around the world typically 2 to 3 years before anybody has even heard about these projects. And so because of that, we saw things coming, so we put it out there. I will tell you, people still didn't necessarily believe. But over time, they did. And then we needed to update it because the original was $7 billion of revenue in 2025 with 15% margins. We updated it to $8 billion of revenue with 18% margins. And another shout-out, Matt Seinsheimer, our Chief IR and Business Corp Dev, coined a phrase, which is really important, a really important takeaway, which is, "That's just a major milestone on a more ambitious journey." So please don't think we've picked that point because that's as good as it gets.

Great. Well, let's talk about orders. Important part of your business, it provides that earnings visibility. You booked $9.7 billion of orders last year. You updated your 3-year order guide so '23, '24, '25, to $30 billion from $25 billion previously with expectations that this year's orders will approach $10 billion. Give us a sense of the $30 billion 3-year number, what's included in that? And does it include some of the activity potential in some of the emerging basins.

Good question. I would say the level of confidence in the $30 billion is -- let's talk about how we built that. We built that on a project-by-project basis. So obviously, you have 2 axes, which is the probability of the project will FID because that's the client's decision, and then the probability that we'll win it. The probability that we'll win it has gotten a lot easier because 70% of our business is direct awarded to our company, so that's become 100%. So that's made the math a little simpler for me. So it really comes down to the probability of the projects moving forward. We're in there, we're at the table early as I discussed, we're doing the front-end engineering. We're doing all the design engineering. We understand what their economical hurdle rate is. We agree to that upfront. So we understand if it's realistic or unrealistic. And then we've obviously got a few secret ingredients in our toolbox in terms of how we can make the subsea architecture the most efficient to be able to achieve the economical hurdle rate. So we go project by project. It's built from the bottoms up. In the past, it's always been what we called a to-be-found because there are things that come along, it's a 3-year projection. There still is a to-be-found. There always will be things that come that weren't in the original forecast. But though there is no to-be-found in the $30 billion number. So the $30 billion is project by project, bottoms up. Now when we go back and look at it at the end of 2025, we'll probably figure out that we didn't get it exactly right, not the $30 billion, but we'll probably figure out that maybe the composition mix by project we didn't get right because maybe one slid into '26 or a '26 project came into '25. But all that to say, very confident because, again, remember, we have a really unique visibility into the market. We're working with the clients today, most of those turn around into direct awards to our company, and we know the status of the projects. We know where they stand. Now we can't predict geopolitical events. We obviously aren't that smart. But we know in the normal project progression when they're likely to go forward. And this is just unique. I mean we never had this before. Everything that I'm describing you today is a result of the creation of TechnipFMC and the attributes of the 2.0 and the iEPCI that we talked about leading to the direct awards.

You've somewhat touched on this, but just wanted to get maybe a little bit more color. How much visibility should investors have about FTI's prospects beyond 2025?

No, that's a good question. Again, please don't think that 2025 is the end, $30 billion is the end. It's interesting sometimes. Look, In our backlog today, in our backlog -- and we show you this, we show you our backlog scheduling for current year, year plus 1 and beyond. So for 2026 and beyond, we already have $4 billion in the backlog. For 2026 and beyond, we already have $4 billion in the backlog. That will continue to grow. Most of the conversations, as I referred to earlier, that I'm having today are all 2028 and beyond. We book something today and we're getting closer to the second half of 2024, you're really delivering that in '26, '27, right? So you're booking today for that period in time. So okay, so point number one. Point number two, as alluded to, I don't know if I said it earlier or not, but of all those kind of walk around the world, those emerging basins, the only one that would probably realistically -- and I'm only saying this because the client has talked about it and I did say it earlier, TotalEnergies has talked about sanctioning Block 58 in Suriname in 2024. So that would fall in that 2023 to '25 time frame. But all those other emerging opportunities are beyond that, which will help support the growth beyond 2025.

My final question is just on margins. Your 2024 guide is underpinned by a Subsea target of 16%. We talked about the 18% for 2025. How should investors view this 18% margin profile kind of next year? And maybe talk to us a little bit about what pricing assumptions are embedded in that.

As a major milestone on a more ambitious journey.

Got it. Okay. Great. All right. We have time for maybe a question or two, from one in the back.

Yes. One question regarding the HISEP project that you told that you separate the CO2 on the seabed, just 2 questions. Can that be done also with water? And since we saw on the last years, the offshore projects globally not being more economically feasible because of gas and of water, could this maybe be groundbreaking for maybe increased oil recovery in projects that were like left behind? Just a little bit about this.

Yes, yes and yes. Absolutely. So we actually do separate and reinject water today on the seabed, not on all the projects, but we do have multiple separation projects ongoing today. We can do the same with gas. Typically, then you have to compress the gas to reinject it, but it's certainly possible. And what's really an important takeaway, and if Luana had the mic, I know she would want me to share or tell you this, I'll do it on her behalf, the HISEP project is a system. I mean this is a mini refinery on the seafloor, many gas -- or not many, this is a gas processing plant on the sea floor. This isn't a single piece of equipment. It's made up of multiple components. Those components can be used in different applications like natural gas, like water, et cetera.

Great. Doug, I think we're out of time. Thank you so much.

Thank you very much.