Good morning, Arun Jayaram again from the E&P and OFS research team from JPMorgan. Welcome to day two of our conference. Delighted to have TechnipFMC to present next. Delighted to have Doug Pferdehirt, who's the Chair and CEO of TechnipFMC, which is one of the industry's largest and most value-added providers of subsea equipment and infrastructure to the offshore industry. Doug, how are you doing?
I'm well, Arun. How are you?
Doug, before starting our fireside chat, I was wondering if you could maybe just start with some introductory comments. We have some generalists in the audience, and maybe you could just talk a little bit about the story and investment case at TechnipFMC.
Sure, I'd be glad to. Let me start by thanking JPMorgan for having us here, Arun, for your hospitality and support, and to everybody in the room and those joining via the webcast for your interest in our company. We don't take it for granted. It means a lot to us, so thank you very much. I always somewhat jokingly say it'll be a Netflix miniseries one day. It's been quite a journey in what we created here at TechnipFMC, so I don't want to give away the, you know, the miniseries up front, but it's a little bit hard to encapsulate. If I try to, just very briefly here, we recognized that the industry needed to change.
We recognized it would take very bold moves in order to change the behavior of the industry and to create an environment where our clients were confident that they could invest in large offshore projects, both in terms of the economics, but also in the certainty of the timing of the project delivery. These have always been the challenges in the past on these large, complex projects. There are prolific reservoirs offshore. Good, solid reservoirs. High permeability, high porosity, naturally flowing, no fracking, minimal flaring, et cetera, et cetera. In order to unlock these, the way that business was done in the past would be multitudes of contractors working together, getting in each other's way, creating a lot of inefficiencies that would lead to cost overruns and delays in the actual project delivery.
We looked around the landscape and we decided if we brought together FMC Technologies with Technip at the time, we could create a new company that would have all of the capabilities to be able to deliver the offshore infrastructure in the water column and on the seabed in one contract with one contractor who would have all of the technology, the expertise, and the competency to do so. That is what created TechnipFMC on the 17th of January, 2017, almost a decade ago. Today, that has really helped transform our clients' economics. We have increased our clients' confidence and certainty of project delivery. As a result of that, the IEPCI, which stands for Integrated Engineering Procurement Construction Installation Contracting Model, has become the industry standard. In addition, we did not stop there. We realized that we needed to look at the architecture itself. The architecture was part of the problem.
It was bespoke. It was first article. It required nine to twelve months of detailed engineering on every single project because we were never building the same thing twice. We went the path of the auto industry and actually learned a lot from Toyota and the Lean Institute and put together what we call a configure-to-order architecture versus an engineer-to-order architecture, much like when you order your automobile. You believe, at least I do, that that auto manufacturer is making that vehicle just for me. I got to pick maybe one of two engine sizes, a manual or an automatic transmission, maybe an upgraded entertainment system and a sunroof and a paint color. I feel really good because I feel like they are building it for me. Guess what? They are putting zero engineering hours. When you hit send on that app, it goes straight into their supply chain.
It goes straight into their internal manufacturing assembly and test. That's how we're doing subsea today. It's revolutionary. So we call it Subsea Studio. It's the app that our clients use. It has the same drop-down menus, slightly different options, 5,000, 10,000, 15,000, or 20,000 PSI instead of, you know, NAV or no NAV, you know, slightly different configurator fit for our architecture. But that means when they place the order, we take out that nine to twelve months of engineering. All the engineering is done up front at those component levels. There's no engineering at the time of the order. This allows us to deliver for our clients nine months to 12 months earlier than anticipated, or they get to achieve production or first oil or revenue nine months to 12 months earlier, which really drives their economics.
It is a combination of this integrated model, this new product architecture, and the fact that we came together as one single entity that has really driven the industry to a new level. The one number that I am going to tell you up front, maybe repeat it once or twice, that really brings it all together because, look, you know, it matters more what our clients say than what I say. Our clients have, and we are humbled and honored by this, given us 80% of our revenue. Eight zero, 80% is direct awarded to our company, never goes out to a competitive tender. That is how unique and differentiated we are in this space, how much our customers trust us, and we are humbled by that.
All right, Doug, let's get started a little bit on the subsea kind of macro kind of picture. How would you characterize, you know, spending patterns in your core traditional deep water markets? Obviously, a lot of commodity price volatility. I was wondering if we could maybe start with some of the core traditional markets, the U.S. Gulf, Brazil, and West Africa.
Sure. So that has always, you know, historically been called the Golden Triangle. It's where 90% of the subsea business has been, and throw in the North Sea in there as well, is really where the subsea industry and the offshore industry has been focused for many, many years. We'll talk later about how that's expanding, which is a major takeaway from this conversation as well. In those core markets, there's still a significant amount of activity. The activity is driven by the fact that the infrastructure and the support services industry exists. If you have the existing infrastructure, it's very easy to add new wells because you can do it in a very short time frame and for a very low capital investment and at about the lowest breakeven that you're going to find in the energy space.
When you originally do an offshore development, the hydrocarbon needs to flow to somewhere. It could flow back to shore through a pipeline, but typically we're far offshore, so it typically floats to something on top of the water, and it's a floating object, whatever it may be. Many are called FPSOs, Floating Production Storage Offloading Units. Let's just go with FPSO. It flows to the FPSO. The FPSO is designed for the initial production rate, which is the highest production rate. One of the challenges in our industry is fields naturally decline over time. The good news is offshore fields decline at a very slow rate, very slow rate, 4%-6% per year, as opposed to the U.S. shale, which can decline 60%, six zero, in the first two years.
When you're offshore, you know that you're going to have a reservoir, again, because of the quality of the reservoirs, that's going to be able to sustain a higher production rate, but it does decline over time. If you look at all those floating objects that are out there in these mature basins today, they're only producing at about 60-70% in nameplate capacity. That's just because of the natural decline rate. The highest production was the very first day, and it declined every day since then. You have that big capital investment that is, if you will, being underutilized today. The ability to add brownfield or tie back wells back to that host facility without any additional capital investment in a host facility makes the economics very attractive.
Now, also in these mature basins, there's new basins, if you allow me to use that term, or new plays within those existing basins. An example of that would be the Paleogene in the Gulf of Mexico, or U.S. Gulf, or Gulf of Mexico. It is absolutely prolific. There are five projects ongoing there today. There will be more in the future. This is deeper. This is a deeper reservoir, but in the Gulf. You get to leverage the fact that there's a lot of infrastructure in the Gulf, but it's a whole new horizon that creates a whole new growth opportunity. In Brazil, they're looking at the equatorial margin now. They've done a lot of seismic work, and now they're starting to look at the potential to do some exploration drilling there. Again, a new play within an existing basin.
There's a lot of activity going on. I didn't mention West Africa. We do expect to see several FIDs in West Africa. West Africa had gone a little dormant for a bit. We see some new projects coming online. We announced one just last year for Shell for the Bonga North project in Nigeria as an example.
Yeah, Doug, we talked a little bit about the traditional core, called the Golden Triangle. What are opportunities to grow kind of the deep water pie and talk about some of the emerging basins globally?
Sure. I talked about the new opportunities within the existing basins. That's number one. Then there's the emerging basins. I will tell you, this is probably for me the most exciting thing about the market today. In my entire career, there's never been this number of new countries or new basins that are going to be coming online offshore. It's phenomenal. I like to travel. I like to meet new people. We just got the first ever project for offshore production in Suriname. It was awarded to us at the end of last year by TotalEnergies and their partner, Apache, to do the project. That'll be, again, IEPCI 2.0, if you will, our special unique characteristics. Just phenomenal. You know, you have, you know, let's start with Guyana. Yes, Guyana has been a phenomenal success, but it's still relatively young.
What Exxon Mobil has and their partners have done there is just absolutely phenomenal. We do all of the work in Guyana, so we are privileged and proud to say that. We earn it every day. You know, we're very excited. We've delivered over 100 trees subsea in Guyana, and we have over 100 trees in our backlog and new orders and new FIDs to come in the future. We're very excited about Guyana. Suriname, I just mentioned, first project end of last year. There are other projects and other operators in Suriname looking at opportunities, and, you know, Total may find additional opportunities there as well. The Eastern Mediterranean is very interesting. It's a gas play. There's a lot of, we know, you know, there's been projects in Israel. There's a lot of activity in Egypt. There's discussions around potential projects in Cyprus, interconnectivity of the three.
There's a lot going on there from a gas reserve point of view. East Africa, a lot of focus on Mozambique, and we expect to see Mozambique projects move forward and, you know, to see new opportunities in Mozambique as well. You have Namibia and Namibia, South Africa, the Orange Basin, extremely interesting, multiple different operators looking at, you know, new opportunities there. We continue to work with those operators to develop the front-end engineering to move those projects forward. Indonesia is more of a mature basin, but it's gassy, and therefore there's a lot of activity right now and new FIDs potentially coming out of Indonesia as well. There are other countries that I haven't mentioned that actually get you to like 2035 and beyond, but I'm really talking about the stuff from 2028 - 2035.
It's just phenomenal how it's lining up and how the queue is materializing. One of the things that's driving that is these host countries have seen the success in Guyana. What has happened in Guyana is truly remarkable for the industry, but more importantly for the Guyanese people. These other host governments and host countries are looking at this saying, this is, you know, we want to do this for our country. We want to do this for our people. They are working very closely with the industry to try to do what they can, given whatever reserves that they have, to get those produced. That means working in a collaborative way to remove barriers and accelerate the FID on these projects.
Great. I want to talk a little bit about order trends. A few years ago, Doug, you outlined the company's expectations. It could book, I believe, $30 billion of subsea orders between 2023 and 2025. You obviously hit your key criteria for the last couple of years. You know, that would imply about $10 billion or more subsea orders in 2025. My question here is, you booked $2.8 billion of orders in 1Q, 1.4 times book to bill. You are ahead of kind of the trend. One of the things we do as we approach the end of the quarter, me and my team, is we look at press releases from FTI. We have not noted any press release orders. I was wondering if you could maybe provide some thoughts.
You hate to focus so much on the near term, but thoughts on 2Q, or maybe just the cadence of orders for the balance of the year. Do you still have confidence on hitting that $10 billion number this year?
Yes.
Okay.
Yeah, $30 billion target over the three years. We're confident in that. That implies $9.8 billion for this year. We remain very confident in achieving that. In terms of the order flow, it's a good question. You know, these are big projects. FID can happen on the 30th or 31st of a month or the 1st of the next month. Unfortunately, being a public company, that can affect a quarter. It's always hard to predict. We do not do quarterly. We just give annual guidance. Our annual guidance was approaching $10 billion for this year, which we remain very confident in. Strong start to Q1, Arun, as you pointed out. In terms of the cadence, as we see it materializing at this time, let me start with kind of the question about the press releases, just for those who do not follow the company as frequently.
There's really three buckets that drive our inbound. One is big press releases, big new projects that, from a materiality point of view, require or we issue a press release. There is a lot of these smaller orders, most of them being direct awarded to our company, which do not reach the materiality threshold for a press release. It is kind of ongoing business for us because, again, we have done decades of work exclusively for some of the largest IOCs. They are just on a cadence of ordering two or three of this or that per month. That just works into our inbound on a continual basis. A lot of those brownfield tiebacks that I talked about earlier, adding four wells back to that floating unit, those are the type of things that would be in that unannounced bucket.
There's the announced bucket, the unannounced bucket, and then our subsea services. It's a very important part of our business. It's very important for you as an investor. It is an OEM model. We supply all the inspection, maintenance, repair, and support of our equipment over the life of our equipment. Our equipment's designed to be anywhere from 25 year-30 year design life, sitting on the seabed one to two miles below the surface of the water. In other words, none of us in this room can hold our breath to get down there. This is all done by advanced automation and control and robotics. It's very, very advanced type things that we do. We partner with NASA in that area because much of the things that we use is what NASA uses in space in terms of the robotics and the automation and control.
Now back to the cadence and how I see things playing out in particular in the near term. No announced awards this quarter. That does not mean there were not big projects. Sometimes our clients will ask us not to announce until a certain date. It may be driven by, you know, reasons outside of our control. Sometimes we will announce after a quarter. It is just unfortunate, but we will announce the project and then say this was inbound in a prior quarter. What I will say is, again, very, very, very confident in achieving the full year guidance of the $10 billion. Strong start to Q1.
If I look at it, I think probably H1 and H2 will probably, you know, it's probably not going to be, it won't be linear, it won't be exactly flat quarter -to- quarter, but I think H1 versus H2 will be in a similar neighborhood.
That's helpful. You talked about some of the longer-term opportunities for FTI and some of the emerging bases and growth and even the traditional bases like the Paleogene. What type of visibility do you have in terms of 2026? You know, one of the questions we get is you've announced so many orders over the last three years or so. Can you keep that pace of order activity into 2026?
Yeah, look, I do not want to get too far ahead at this stage, but I would say when we look at 2026 and I will even tell you 2027, we have a robust list of projects, you know, projects, named projects, not, well, we think somebody might do a project. These are named projects that would support a very healthy order rate. What I have said is that we do not see a cliff and we do not necessarily see a plateau at this time. There is a very healthy order rate and quantity of projects out there. Keep in mind that 80% direct award. So we have unique visibility into the market that the rest of the market does not have because our clients are working with us on an exclusive proprietary basis to develop these front-end engineering studies to allow these projects to achieve FID.
We can be involved in typically our two to three years before that project ever makes it into the public domain. Because of that, because of that visibility that our clients provide to us, which we are, you know, privileged to have and humbled to have, I will tell you we remain very confident in the offshore activity. All that I just said has nothing to do with all those emerging countries we talked about in an earlier question because they're all largely, largely 2028 and beyond. Some you could see in 2027, but it's what drives this thing, you know, you know, into the future.
Yeah. Next question is maybe could you briefly describe your Subsea 2.0 offering?
Briefly?
Yeah.
I think I.
Ground to cover.
I think I kind of got it earlier. Again, in the past, our customers would tell us exactly how to build something. Exactly. They would give us the specifications and they would say, "Go out and build it." As an industry, we just accepted that. We knew it was not efficient. We knew it was disruptive. We knew it required an additional 9 months-12 months of engineering because we have to take their requirements, turn those into engineering specifications, and then build it ourselves or use our supply chain. Everybody is doing everything for the first time. Inefficient, ineffective, very costly. We moved to this configure-to-order, like the auto industry, where we worked. It took us six years of intensive engineering and working with our clients to get them to agree on those subcomponents.
We said, "Okay, there's going to be three types of choke. There's going to be two types of flow loop, whatever it may be. Would you agree that this covers 99.9% of your needs?" We got there with our diverse set of clients. Then we were able to put together this configurator. Subsea 2.0 is just truly unique in that it's the only way that the industry has to build something reliably, both in terms of cost and in terms of schedule versus the traditional bespoke manufacturing way that we did, which is Subsea 1.0 or which is the rest of the industry today.
Could you maybe elaborate on this concept of an integrated project? There's projects where, you know, TechnipFMC does, you know, the lion's share of the SURF work, but there's projects perhaps like Suriname where I think you're partnering with Saipem. Give us a sense of the differences.
Sure. We're excited. Suriname is an iEPCI project. It's an integrated project. In that case, when we looked at the most optimal way to develop the asset, we decided to partner with another company, in this case, Saipem, who is part of our vessel ecosystem, which is a group of companies who want to work on our iEPCI projects. I mean, it just really is as simple as that. Remember, we talked about iEPCI, the majority being direct awarded to our company, et cetera, et cetera. Those who have the vessel, those we have vessels. Our plan has been and continues to be asset light. We've reduced our number of vessels while we've significantly grown the company. We do that because we can do things more efficiently.
If we can take 9 months-12 months off of a project and deliver a project in two years instead of three years, in essence, I have 33% more capacity without spending any capital. We're not done. 9 months -12 months, we're going to keep taking time off that schedule. One, it makes us very competitive for our client's capital because it's shorter cycle. It's more predictable. Also, I'm doing more with the same. I don't have to spend capital to grow, which is also one of the key attributes that are driving our returns and making our returns much more sustainable. From time to time, we do need other vessels. It is very common on our projects to use third-party vessels.
In that case, we have an ecosystem of partners or we can go to the third-party market, but then we'll just contract what we need at that time for those projects.
Great. Subsea services is something you highlighted. You know, I believe last year you generated about $1.65 billion of revenue, being precise here. What are your forward expectations for growth kind of in the segments and how do margins generally compare to call it your equipment types margin than just the subsea equipment?
Good question. The $1.65 billion in 2024, we indicated we thought it would grow to about $1.8 billion in 2025. It is a substantial part of our business. The easy way to think about it is the growth rate plus or minus the same growth rate as the overall subsea business. It is more or less in line with that. The profile of the business is, I guess, what is really most interesting, and it is these long-duration contracts. Think of it kind of more like an industrial type play. Very predictable OEM. You do achieve good margins on that business. Now, unlike some other businesses, you do not give away, you know, you do not give away the product to get the sale, you know, the service tail on it. We get a good margin on both, but the service margins are certainly very attractive.
Okay. Let's talk a little bit about margins. One of your customers just walked in the back, so just maybe be careful with this one. Your 2025 guide implies about 19.5% EBITDA margins. One of the things that we learned at the dinner last night is only about a third of your throughput today is Subsea 2.0. Broadly, talk to us on where you're at in terms of this margin journey.
Sure. The margins have been expanding. It has really been driven by the internal efforts that we have been taking. When we work with our clients, we focus on cycle time. If we can deliver subsea equipment significantly earlier than the competition, with certainty, it drives their economics. It improves their project returns. We sit down at the table early on. We agree on an economical hurdle rate. We work together in a collaborative way with our engineering team, with their engineering team to design a subsea architecture and a delivery system, i.e., the equipment and the installation, and that is the iEPCI. It can improve the returns from the client because they are getting first-to-first oil sooner, recognizing revenue sooner, and with certainty, which is very important to them.
We get the benefit of the efficiencies of our internal, as I said, I think to an earlier question, doing more with the same or more with the less. That is how we are able to gain a win-win situation where our clients remain very happy, hence the 80% of our business being direct awarded to our company because they are seeing the benefit. They are realizing the benefit. Then we get the benefit from our own internal efficiencies.
Yeah. I was wondering if you could talk a little bit about the flexible pipe market and maybe the steps the company's taken to commercialize a new composite flexible pipe solution, which could have some really interesting market in Brazil.
Sure. Look, the flexible market remains very strong. There are three companies who do that. We are the market leader. We continue to drive the technology development in that market. It is a very unique technology that is very important to our integrated project offering. It allows flexibility, no pun intended, to the way that our customers go about their field development, which reduces their overall cost. The biggest market for flexible pipe today is in Brazil. Petrobras, you know, was one of the early adopters and really driven the application of flexible pipe, both in terms of their flow lines as well as the riser systems. As they moved into the pre-salt developments, which has a very high CO2 content, they started to experience what is called stress corrosion cracking, which is a natural phenomenon of hydrogen embrittlement in any steel product, be it rigid pipe or flexible pipe.
They started to look at alternatives to try to mitigate that, coatings, et cetera, things like that. They have been working with us for a number of years, and we've had a technology development going on for quite some time to come up with a SCC compliant solution that would permanently remove the risk of hydrogen embrittlement. We're doing that by coupling the traditional flexible pipe, which is, think of it as strands and layers of steel, with a PEEK material, which would not be porous and would therefore you wouldn't have the opportunity to have hydrogen embrittlement as a result of water encroachment. We're working on that. We have an ongoing qualification program with Petrobras. We believe we have the industry's only true SCC compliant solution, and we're excited to bring that to the market here in a couple of years.
Great. We have time for one question.
Hello. Thanks for the question. Regarding the Petrobras contracts, you have a new technology that's in place being deployed in the next three years that's the HISEPS that looks, when we look at what means the engineering, what it seems kind of a bit a breakthrough in order to expand into fields with higher CO2 and higher, I mean, problems with gas. If you could talk a little bit about it, how it's being developed and when should it start to operate? I believe in Mero field, but what size of breakthrough? Because Petrobras says that it could be used in much other fields in order to revamp the production since you can on the seabed separate the CO2. It looks good, but we can't understand what it could mean for the whole offshore industry.
Sure. Thank you very much. My timer is blinking red at me, so I'll be very quick. Wonderful question. The head of our business, Luana Dufay, is here, and she's actually the one responsible for this project. Look, it is a phenomenal project. It really tells, you know, we did not talk much about how we develop technology. We talked about it in flexible pipe, but HISEPS is another example. The industry had a problem. CO2 is not something that is a, you know, you do not want to produce the CO2 if you do not have to produce the CO2. You basically today have to bring the CO2 to shore or to the top side. You have to separate it. You have to re-inject it.
We worked with Petrobras for seven years to develop a novel technology that allows us to separate the CO2 on the seabed and re-inject it. It'll never come to the atmosphere. It'll reduce their greenhouse gas footprint by 30%. It increases their production because it's in a mature field. Instead of producing the oil and the CO2 up to the FPSO, now it'll be less CO2 or ultimately CO2-free. It is a major, major, major technology development that we did together with Petrobras. We are very excited. Yes, it's being used on the Merrill III project initially, but we would expect that to expand and unlock other opportunities. Thank you for the question.
Great. Doug, thank you so much.
Okay. We're going to keep things moving. Our next presenter is Murphy Oil. Delighted to have Murphy's new CEO, Eric Hambly, to participate in a fireside chat with us today. Even though he's the new CEO of Murphy, he's been at the company for quite a bit of time, around 20 years. He's really grown up throughout the organization, leading the operations since 2020. He joined, like I said, Murphy in 2006 and has been leading the company forward since January. The excitement here is just a few days after he became CEO, he had the pleasure of announcing a world-class discovery in Vietnam. A great and amazing start to your tenure, Eric. Before diving into our fireside chat, I was wondering if you could just start off with some introductory comments around the company, Eric.
I appreciate that, Arun. Thanks for having us to your conference. I think I heard today that we are at your 10th, 10 out of 10 conference.
Yes.
Murphy, big supporter, and we appreciate your support of us over the years. I think we have an exciting future ahead of us at Murphy. I think we're a very different company than many of the companies that are kind of our scale. We have an onshore and an offshore business. We've maintained the capability of doing international exploration and development, and we have a large inventory of remaining shale locations. I think that as we head toward the end of this decade, it sets us up to be really differentiated compared to companies that are really many were close to our scale. We'll talk probably more in this Q&A, but I think we have an exciting exploration and appraisal program in front of us.
We're on the cusp of building what looks to be a material business in Vietnam with a development project, Golden Camel, the Hai Su Vong Golden Sea Lion recent discovery, and another Pink Camel discovery that we just made. I think we're setting up for a really successful future for Murphy in Vietnam as we head toward the end of this decade. I think over time that'll increasingly make us look a lot different than other companies and a compelling story in terms of investing in.
Eric, before diving into the fundamental story here, I mentioned how you just started as the CEO just a few months ago, which has given you perhaps a fresh license to look at the organization, your leadership team, and strategy. I'm wondering, any kind of perspective and any thoughts on tweaks to the organization or strategy?
Yeah, that's a great question. Fortunately, I had the opportunity to work over the last few years to help shape the Murphy strategic priorities, key objectives, and focus areas. That's something that Tom Morales, our CFO, who's here, and Roger, our prior CEO, worked on quite a bit with our board. As I start my tenure as CEO, I look and see that the things that we would like to be doing better or do differently, I was able to help shape the implementation of that over the last few years. I think we're starting to see some success from that. For example, I think that our exploration organization, we worked over the last two years to significantly improve the capability of our team, our process around acquiring and analyzing data before making decisions about which wells to drill from an exploration perspective.
I think you can see over the last year or so, the results that we've demonstrated are showing that the success of that work has come to bear. The other thing, I had a little bit of a discussion at dinner last night around some companies, some of our peers that are really focused on cost reduction efforts. I'll just point out that in 2020, Murphy had a major cost reduction effort that we significantly streamlined our organization and our cost structure. In 2019, we had annual G&A of $243 million. The last few years, we're running about $110 million -$107 million. What companies may now be doing to cut costs out of their structure, we really did in 2020. It's an effort that I worked on with our senior HR leader, Maria, and kind of led an implementation of that in my prior role.
A lot of the things that you might look to say a new CEO may do, we've already kind of done, and I was able to help shape it. I feel really good about our organization, our capability, and really, really happy of the recent success in improving our exploration organization.
Okay. Let's dive into the 2025 program. Your budget is earmarked to spend about $1.2 billion of capital, with 85% of the budget earmarked for development. Can you talk about how you're thinking about kind of the macro picture and where Murphy stands in terms of kind of executing its original program?
Yeah, we're very happy with the capital program that we laid out for this year and our longer-term guide of a typical year being between $1.1 billion and $1.3 billion capital program. We're happy with that, with oil basically in the 60s. We easily cover our dividend and our capital program with oil prices in the 60s. We highlighted in our first quarter earnings call recently that if we saw oil prices that were lower for a sustained period of time, like maybe say $55 a barrel, WTI, that we thought would be a long duration, that we might make adjustments to our capital program. The reason to do that would be to basically protect our balance sheet, which we think is currently industry-leading, really solid balance sheet.
We want to keep that to be able to be opportunistic to fund successful exploration, to potentially go after M&A opportunities that other people may not be able to do. We'll be a bit careful. With the prices we're seeing now and what we think looks like next year, we should pretty much stick with that type of capital plan. When the capital plan we put together, that $1.1 billion-$1.3 billion kind of in a typical year, we allocate about 10%-15% of that for exploration. The rest of the business is a combination of sustaining basically a steady performance of production level from our onshore business. Eagle Ford, we're managing in a 30,000-35,000 barrel a day net to us range. Our Tupper Montney business, we're periodically refilling to our plant capacity.
The rest of the investment, other than the exploration, which I highlighted, is development activity for the Gulf of Mexico primarily. We have a steady plan of activity through the end of this decade to continue to develop our assets in the Gulf of Mexico , which should provide single-digit, low single-digit growth in our business. You add our Vietnam new production coming online in 2026 to that, we start little step-ups over time between now and the end of the decade.
Great. I want to dig deeper a little bit on the portfolio. Let's start with the Gulf. Can you provide kind of an update on your plans and with the drill bit in 2025?
Sure. Let me go back to the beginning of 2025. In the first quarter, we brought online the Mormont number four new development well. In the first early part of the second quarter, we completed a workover on the Samurai #3 well. Those are already online. In the second quarter, we are progressing workovers at the Khalisi #2 and Marmalard #3, which should have first production in the second quarter and the third quarter, respectively. That should be the end of our offshore workover program, which, as you are familiar with, has been a bit of a sore point for us over the last few, well, the last 18 months or so. Rounding out the rest of 2025 in the Gulf of Mexico, we have two exploration wells planned that we will drill in the third quarter. They are called Cello and Banjo.
They're near our Delta House operated facility. With success, we'll have the ability to fairly quickly tie them in and bring them online. They're not expected to be really large resource opportunities, but they're highly accretive and quick to bring online. In the Gulf, we round out the year drilling a new well in Samurai, which will come online and be completed in the early part of 2026. On top of all of that, in the Gulf, we have some long lead acquisition of equipment, long lead equipment in 2025 to support operated and non-operated wells in 2026 and 2027. That's kind of how we're spending our money and what we're developing in the offshore space.
Okay. Maybe a quick update on the St. Malo water flood project with Chevron. Where do you stand with that? When can you start to see some production from that project?
The St. Malo water project was substantially completed last year and water injection began. What we expect to see over time is the water injection will provide pressure support in the reservoir, which will help sustain a production level that's sort of steady. The water flood contribution over time will be larger and larger. At this point right now, we're not yet clearly able to distinguish what is sort of base performance from water flood performance. We do expect throughout 2025 to start to see a contribution from the water flood project and increasingly in future years, more and more of the total production will be from that. What's interesting about sort of typical deep water fields, if there is a typical one, decline rate of without activity is typically somewhere around 18%. We're basically not seeing decline at the St. Malo field.
The water project, while early, it's probably starting to show some performance.
Okay. It sounds like the workover program is largely in the rearview mirror. How do you think about kind of normalized workover? Obviously, the last, call it 12 months -15 months, you've had a little bit higher of equipment workovers, but it sounds like you'll be moving to more of a normalized level of workover spend.
I sure hope so. If we look at a typical year, we do not expect to have any offshore workover activity. If you look back over the period of time from 2023 back to say 2018, we might have had one offshore workover in our deepwater Gulf of Mexico business. It is normal for us to expect to have a year without any workover activity. We have, as I just mentioned, had quite a year plus of quite a few high-rate wells that needed to be worked over. What is interesting about them is the wells all had issues with different pieces of equipment. There is not a commonality. There is not the same type of equipment or the same failure mechanism for the well.
We feel like once we get past the work that we are aware of, that it'll be normal to expect no repeat and kind of get back to lower operating expenses.
Yeah. One of the things that I think you did have to do is replace some subsea safety valves on a number of wells. Where are you in terms of that process?
Yeah. The Dalmatian well, we had a safety valve repair in 2024. That well has been back online and producing. The Khalisi #2 that we're working on in the second quarter is also a safety valve repair. What's interesting is there are two wells of completely different vintages and totally different types of safety valves. Safety valve failures are not very common in the Gulf. We were quite surprised to have them. The Dalmatian well produced, I think, for eight years or so before having any type of issue, whereas the Khalisi #2 well was about two and a half years old. Again, totally different types of safety valves, fundamentally different designs. Fairly unusual to have something like that happen. I think, like I said, I think we've turned the corner and we're getting back to kind of normal run rate.
Our total company operating expenses, when we do not have significant offshore workovers, they are kind of typically in the $10-$12 per BOE range. I think you should see us get to that kind of level in the latter half of the year.
Okay. One maybe final question on the Gulf of Mexico. I'd love to get an update on Chinook and maybe you could set the stage because I think that could be a really interesting well for you for next year, I believe.
Sure. The Chinook field, the Cascade and Chinook fields produce to an FPSO, which we purchased early this year for a little over $100 million. That sets us up to have a lot better creative economics of a development project there. We've been aware of a development opportunity to replace a well, which was previously producing from one of the Chinook reservoirs for quite some time, but we weren't moving it forward because we had a fairly high day rate under a lease agreement for that FPSO. Now that we've purchased the FPSO, we have a lot of flexibility in what we want to do. What's interesting about Chinook is we have quite high ownership. We're over 86% working interest.
The well that we have in mind, which we'll likely include in our 2026 budget and will likely come online in the last half of 2026, has the potential to be pretty high rate on a net basis. It might be up to 15,000 barrels a day. It is a pretty compelling opportunity for us with really strong economics. It is a developed field, so we do not have a lot of subsea infrastructure we have to install. Thankfully, Doug was talking about how much cost pressure they are putting on us, and we will not have a significant amount of that for this project. The timeline to bring it online would be a pretty quick drill complete tied in.
Is that fair to characterize this more as a development slash well versus?
It is. It's a development well. It's targeting a reservoir that's been developed and is producing, but we need to have another well to have another take point in the reservoir to optimally produce. There was a well that was producing in that pre-2019, which had demonstrated rates that were in that range. There is quite low subsurface risk in terms of the outcome.
I got to think, and maybe I'm getting down too much in the detail, but is an EUR for that type of well, $20 million-$30 million barrel kind of.
That's a fair assessment, yes.
Okay. Great. Great. Again, you plan to drill that in the second half of 2026?
We'll start drilling it sometime probably in the second quarter of 2026, but it'll take a while to drill. It's a fairly deep well, and it'll probably come online in the, I don't know if it's the third or fourth quarter, probably the fourth quarter of 2026.
Yep. We've had some ebbs and flows in terms of offshore service costs. Doug, who presented how to use, has obviously been pushing margins, but there's been a little bit of slackness in the deepwater rig market. Talk to us a little bit about the strategy and maybe where you're seeing in terms of pricing and your contracting strategy.
Yeah, great question. We're seeing a bit of a mixed bag in terms of offshore costs. We recently extended a rig contract for a drill ship we've been using now for a number of years out through what is our planned activity through the middle of 2027. The rig rate has some adjustments through time, but it's basically the day rates are about 15% lower than what we were seeing in the market last year. We are seeing a softening of drill ships through that period of time. Other significant costs, the day rate of a drill ship is about 40% of the cost of a deep water well, a big piece of our business. Other things, other services are basically stable costs.
We have kind of a rolling series of contracts that our procurement team works to renew through various means that most of the services have been pretty stable. Of course, diesel is a significant part of our cost, which moves around with oil price. Two areas where we're seeing cost increases that are one modest and one more significant is the more modest increase we're seeing in tubular goods. So offshore wells, just the casing, the steel tubing, etc. in our program, we're seeing probably around 5% type of cost increases this year compared to last year. And then for major subsea projects, trees, umbilicals, risers, the things that we get from people like TechnipFMC, we're seeing compared to our last major greenfield project, which we brought online in 2022, we're seeing 30%-50% cost increase. It's a lot of pressure there.
It's one reason why I'm really excited to have some success in a shallow water Vietnam because I don't need any subsea trees or umbilicals or risers of that kind of nature from what's really a hot market with a lot of demand across the industry and consolidation in that space.
Great segue, Eric. I was going to ask you about Vietnam. The company reached FID on the Lac Da Vang development a little bit of time ago. It's about a 100 million barrel gross field. Can you provide an update on this project, which is targeting a first oil in the fourth quarter of next year?
Sure. We're really happy with our execution of the project there. When you do a new greenfield project in a country that you haven't been active in before, it's always interesting to get a sense for the capability of the construction yard and the people we work with and the talent. I've been very, very happy with how it's going so far. Major milestones for the project are building the Lac Da Vang A platform and building an FSO. It's a floating storage and offloading vessel, which is basically a big storage tank with a turret. Along with that, we'll install some sort of infield pipelines. Execution of the project is going very well. We're very happy with it. We're definitely on track for first oil in the fourth quarter of 2026. Sort of key milestones to be paying attention to there.
The jacket for the platform will be installed in 2025, probably in the third or maybe early fourth quarter. We will begin drilling development wells from that location. The top sides for the platform will be built in, will be installed in 2026 along with the FSO in 2026. We will bring the field online.
Okay. How should we think about kind of the CapEx outlay for this project? Because it is kind of a phased development with a couple of platforms.
That's right. The overall development will spend between 2024 and 2029, we'll spend net to Murphy about $380 million. $110 million is what we allocated for our budget for 2025. Next year's spending is probably on the order of $90 million. We'll have first oil after spending maybe two-thirds of the total capital program roughly. In 2028, we'll likely install a second, simpler wellhead platform where we'll drill the other half of the wells for the development. It is sort of a spread out capital program from over many periods. Production likely peaks in the 10,000-15,000 barrel a day net to Murphy in the 2027-2028 timeframe. As we continue to add wells through 2029, we should see relatively stable production.
We start to see when we finish drilling wells, we'll start to see decline probably at the end of the decade.
Okay. Let's talk about the Hai Su Vong discovery. Again, just announced just a few days after you became CEO. Obviously, you're involved with that whole process. Talk to us a little bit about what you think you've found thus far with the discovery well.
Yeah. What we've announced so far about the discovery well was that it was drilled at the crest of the structure. The main pay that we discovered is a large four-way structure. We drilled close to the crest. We flow tested the well at 10,000 barrels a day, which is an extremely high rate for a well in shallow water, 150 ft of water. What we found in the well is consistent with our pre-drill range of expectations for the field, which was 170 million barrels equivalent to 430 million barrels equivalent. What we do not know now because of where the well was drilled, we do not know how much of the structure is filled with oil. The discovery well encountered only oil and no water. We do not know where oil-water contact is. The structure is quite large.
The appraisal well that we have planned to start drilling in the third quarter will be drilled off the crest of the structure. The main objectives are to test for the continuity of the reservoir over a large distance and also hopefully help us get a better view for how much of the structure is oil-filled. That could help us firm up our range of resources for the field. It has potentially to be pretty large. I do not like to get too ahead of ourself. I would like to see the result of the well before we say more about it. It is pretty exciting. The discovery that we already are aware of from just what we have identified in the well is a commercial development. That is a standalone scale development that we will be able to develop.
We're excited, hopefully, to potentially prove up a larger resource with some appraisal success.
Okay. Great. You did announce a discovery at Pink Camel last quarter, maybe not the same size as Hai Su Vong, but still a great outcome for the company. Talk to us about that discovery and plans to develop that.
Yeah. That's a nice discovery for us. We expect that that field is somewhere in the 30 million -60 million barrels oil equivalent. I'll mention that these fields for us in our Cooling blocks, they're very oily. They're 90% plus oil. So we give you BOE numbers, but they are quite oily. We will likely develop the Pink Camel or Lac de Hang field as a wellhead platform tied back to the infrastructure of the Golden Camel development that we're doing now. The Pink Camel field is three miles away from our infrastructure LDVA. So very close tie back. We needed to find something on the order of 8 million -10 million barrels to have a commercial development. And we found what we think is 30 million-60 million. So it should be quite successful there.
One thing to note, the PSCs that we have in Vietnam, they have ring fencing at a block level. Once we establish revenue from Golden Camel or LDV field, we'll start to recover costs from all of our investment in the block, including exploration. Pretty attractive opportunity for us there.
Good segue. How do you think about the attractiveness of this PSC versus elsewhere that you look at globally?
The terms of the PSC in Vietnam have an overall government take over the life of a typical field that is pretty consistent with the Malaysia business that we built over many years. That might be a 65%-75% take. The oil companies get a lot of their return early, and then later on, the government gets more. It is pretty typical of PSCs. Indonesia PSCs typically have a little higher government take. It is more competitive. If you contrast that with our business in the rest of the world, obviously the government take in the Gulf of Mexico is the best system fiscally in the world. In Côte d'Ivoire, where we have five blocks, the government take is not much different than the U.S. It is a little higher.
Really compelling there if we have some exploration success or a development project there that the government take is set up to be something that we can do quite well financially.
Let's talk a little bit about West Africa, Côte d'Ivoire. Eni is at the conference, but your acreage position is bookended by two significant discoveries by Eni, Baleine and Marine. Maybe just talk about your plans and opportunity set in Côte d'Ivoire through the drill bit.
Great. We're going to start drilling a three-well program in Côte d'Ivoire in the fourth quarter. That program, the first well in the program will be Cevette, which is 10 kilometers away from the Marine One X discovery well on the field that they call Calao, which they announced, Eni announced in March of 2024. Geologically, the Cevette prospect is very similar to the Calao discovery. It's testing the same age reservoir, just slightly shallower interval. We're really excited about it. It looks very similar geologically to what is a very close success. The Calao discovery goes a long way toward demonstrating a working hydrocarbon system, petroleum system. It is possible that the Calao discovery extends onto our block. We don't know that yet, but it looks like it from assessing the seismic data. We're really excited about the prospect.
The size of that Cevette prospect is over 400 million barrel mean with up to a billion barrel upside. Something of significant scale for us. We still have some work to do to award the contract for the rig and also finalize the estimate of the cost of the wells. Sort of ballpark, we're talking about $50 million-$60 million gross well costs, which is pretty compelling to spend that type of money and test something of a scale that could be 400 million barrels plus with good fiscal terms. The other prospects that we have planned, likely the next prospect will be one called Caracal, which is geologically similar to the producing Baleine field that Eni discovered in 2021. We do not think Caracal is as large as Baleine, which is sort of a billion barrel recoverable scale, but it does look very similar.
It's fairly close by. It has the same age reservoir and the same sort of geologic features. We think we're bookended by what are compelling analogs for what we'll drill, and we're really excited about it. The third prospect that we'll drill is likely to be more of a frontier testing, less demonstrated successful plays, some plays that work in the larger Tano basin, including in Ghana, but a little more frontier and therefore a little higher risk. Again, large opportunities with low well costs. We're really excited about that. We'll have some pretty exciting results to talk about. If you kind of step back and look at the testing we're going to do with appraising in Vietnam and the three-well program in Côte d'Ivoire, the sum mean unrisked resource of those opportunities is five times the size of our current offshore approved reserves.
With success in any of them, it has a pretty material impact to our company.
Yeah. Market will definitely be well watching regarding Murphy.
I'm pretty sure our share price will go down if we announce a discovery because of concerns about additional CapEx.
Got it. Got it. Let's talk about maybe the technical team because what type of knowledge base do you have internally in terms of your explorationists with West Africa?
The exploration team we have assembled has a diverse set of experience of quite a few basins around the world. We typically have most of our senior technical hiring is from people that work at super major or other types of companies and come to work for us because they like to work for small companies that still explore, and there aren't that many of them left. We have a team that's very experienced. We do supplement that with some earlier career people, but we have people on our team that have a lot of experience in the Gulf of Mexico and West Africa. We are really well positioned for executing a nice program there.
Maybe final question on West Africa is Anadarko's legacy pond discovery. I believe it's your intention to submit a field development plan to the government by year-end, subject to kind of a gas sales agreement. Where do we stand with that process?
Yeah. The pond field is very well appraised by Anadarko before they relinquished the block. It is a relatively small field. It's an oil field with a thin oil column and a large gas cap. Negotiating the terms of a gas sales agreement is one of the critical things in determining whether or not that's an economically viable project. We have a work obligation for the PSC to submit a plan of development for the field by the end of this year, which we're well on track to do. In parallel with that, we're negotiating with various Ivorian government parties around a gas sales agreement. We may or may not come to terms with them that will lead to a commercial project. It's kind of a coin toss at this point, whether it's something that happens or it doesn't happen.
In the country, Côte d'Ivoire is importing diesel and using it to generate electricity. The legacy supply of natural gas that they're using to generate power at their thermal power plants, the legacy supply is in screaming decline. The additional gas volumes coming from Baleine, the way we understand it, are not enough to meet the demand. So the country really has aspirations and needs some more natural gas, but they have to be willing to pay what it takes to make a fairly marginal project happen. We're trying, but we don't know if it'll happen or not. It's sort of a 50/50 at this point.
All right. Sorry to ask you this question, Eric, but we're the last conference before 2Q earnings season is here, five days away. How are you feeling about 2Q, how the rest of the year is kind of setting up for you?
I'm very happy with our operations as we progress through the second quarter. We will, as typical in our early August earnings call, give a full update on our 2Q performance and also kind of an updated view of what the full year looks like. I'm pretty happy with how we're executing both offshore and onshore.
Great. Why don't we cut it off there? Thanks, Eric.
Thanks so much.
Appreciate it.