TechnipFMC at J.P. Morgan Conference: Subsea Growth Ambitions

On Wednesday, June 25, 2025, TechnipFMC (NYSE:FTI) presented at the J.P. Morgan 2025 Energy, Power, Renewables & Mining Conference. The company highlighted its strategic position in the subsea market, showcasing both strengths and challenges. CEO Doug Fertihert expressed confidence in achieving substantial order targets, while acknowledging potential market volatility.

Key Takeaways

• TechnipFMC aims for $30 billion in Subsea orders from 2023 to 2025, with $9.8 billion expected in 2025.
• Murphy Oil focuses on international exploration, with significant developments in Vietnam and the Gulf of Mexico.
• Both companies emphasize technological advancements and strategic growth despite cost pressures.
• TechnipFMC’s Subsea Studio configurator reduces project delivery times by 9 to 12 months.
• Murphy Oil’s 2025 capital program is $1.2 billion, with 85% allocated to development.

Financial Results

TechnipFMC:

• Targeting $30 billion in Subsea orders between 2023 and 2025
• Expecting $9.8 billion in orders in 2025
• Q1 orders of $2.8 billion, with a book-to-bill ratio of 1.4
• 2024 Subsea services revenue of $1.65 billion, growing to $1.8 billion in 2025
• 2025 EBITDA margins expected to be 19.5%

Murphy Oil:

• 2025 capital program of $1.2 billion, with 85% for development
• Typical annual capital program ranges from $1.1 billion to $1.3 billion
• Eagle Ford production managed at 30,000 to 35,000 barrels per day
• Vietnam development costs $380 million, with $110 million budgeted for 2025
• Operating expenses range from $10 to $12 per BOE, excluding offshore workovers

Operational Updates

TechnipFMC:

• IEPCI model is now the industry standard
• Subsea Studio configurator reduces project delivery times by 9 to 12 months
• Partnering with Saipam on Suriname IEPCI project
• Developing SCC compliant flexible pipe and HYSEP technology with Petrobras

Murphy Oil:

• Gulf of Mexico: Mormont No. Four and Samurai-three wells online
• St. Malo waterflood project completed, with water injection started
• Vietnam: Lok Da Vang development on track for Q4 2026 first oil
• Cote D’Ivoire: Three-well exploration program planned for Q4 2025

Future Outlook

TechnipFMC:

• Expects robust order rates into 2026 and 2027
• Emerging countries anticipated to drive growth beyond 2028

Murphy Oil:

• Gulf of Mexico development expected to provide low single-digit growth
• Vietnam production stable through 2029, with ongoing well additions
• Cote D’Ivoire field development plan submission aimed by year-end

Q&A Highlights

TechnipFMC:

• Addressed order cadence and project timing impacts
• Clarified annual guidance approach, without quarterly specifics
• Explained Subsea two point zero as a configure-to-order solution

Murphy Oil:

• Discussed capital allocation between development and exploration
• Highlighted Chinook development potential as a high-rate producer
• Addressed offshore service cost impacts on project economics

Readers are invited to refer to the full transcript for a detailed account of the conference discussions.

Full transcript - J.P. Morgan 2025 Energy, Power, Renewables & Mining Conference:

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Good morning. Arun Jayaram again from the E and 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 Fertihert, 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?

Doug Fertihert, Chair and CEO, TechnipFMC: I’m well, Arun. How are you?

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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.

Doug Fertihert, Chair and CEO, 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 miniseries upfront. But it’s a little bit hard to encapsulate.

But if I try to just very briefly here, we recognize 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, etcetera, etcetera.

But 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, expertise and the competency to do so. That’s what created TechnipFMC on the 01/17/2017, almost a decade ago. And today, that has we’ve really helped transform our clients’ economics. We’ve increased our clients’ confidence and certainty of project delivery.

And 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 didn’t 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. So 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.

But I feel really good because I feel like they’re building it for me. But guess what, they’re 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 dropdown menus, slightly different options, 5,000, 10,000, 15,000 or 20,000 PSI instead of NAV or no NAV. 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 upfront at those component levels. There’s no engineering at the time of the order. This allows us to deliver for our clients nine to twelve months earlier than anticipated or they get to achieve production or first oil or revenue nine to twelve months earlier, which really drives their economics. And it’s 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. And the one number that I’m going to tell you upfront, maybe repeat it once or twice, that really brings it all together because look, it matters more what our clients say than what I say.

Our clients, and we’re humbled and honored by this, give us 80% of our revenue, eight zero, 80% is direct awarded to our company, never goes out to a competitive tender. That’s how unique and differentiated we are in this space, how much our customers trust us, and we’re humbled by that.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: All right. Doug, let’s get started a little bit on the subsea kind of macro kind of picture. How would you characterize spending patterns in your core traditional deepwater markets? Obviously, lot of commodity price volatility. But I was wondering if we could maybe start with some of the core traditional markets, The U.

S. Gulf, Brazil, and West Africa.

Doug Fertihert, Chair and CEO, TechnipFMC: Sure. So that has always 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 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 this conversation as well. But 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. So 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. So when you originally do an offshore development, the hydrocarbon needs to flow 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. So let’s just go with FPSO. So it flows to the FPSO. So 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. Four to 6% per year. As opposed to The US shale, which can decline 60%, six zero, in the first two years. So 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. So if you look at all those floating objects that are out there in these mature basins today, they’re only producing at about 60% to 70% of nameplate capacity. And that’s just because of the natural decline rate. The highest production was the very first day and it declined every day since then. So you have that big capital investment that is, if you will, being underutilized today.

So 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’ll 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 America, or The U. S. Gulf, or Gulf Of Mexico.

So it’s absolutely prolific. And there’s five projects ongoing there today. There will be more in the future. And this is deeper. This is a deeper reservoir but in The Gulf.

So again 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. So there’s a lot of activity going on.

I didn’t mention West Africa. We do expect to see several FIDs in West Africa. So 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.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Yeah, Doug. We talked a little bit about the traditional core, call it the Golden Triangle. What are opportunities to grow kind of the deepwater pie? And talk about some of the emerging basins globally.

Doug Fertihert, Chair and CEO, TechnipFMC: Sure. So I talked about the new opportunities within the existing basins. That’s number one. And then there’s the emerging basins. And 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 was awarded to us at the end of last year by Total Energies and their partner Apache to do the project.

That’ll be, again, IEPCI two point zero, if you will, our special unique characteristics. But just phenomenal. So have let’s start with Guyana. Yes, Guyana has been a phenomenal success. But it’s still relatively young.

And what ExxonMobil, Hess, 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. And 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.

So 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. 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 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 to see new opportunities in Mozambique as well. Then you have Namibia. And Namibia, South Africa, the Orange Basin, extremely interesting, multiple different operators looking at new opportunities there. And 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’s 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 to 02/1935. It’s just phenomenal how it’s lining up and how the queue is materializing. And 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. And these other host governments and host countries are looking at this saying, we want to do this for our country, we want to do this for our people. So they’re working very closely with the industry to try to do what they can, given whatever reserves that they have, to get those produced. And that means working in a collaborative way to remove barriers and accelerate the FID on these projects.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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, 30,000,000,000 of Subsea orders between 2023 and 2025. You obviously hit your key criteria for the last couple of years, and that would imply about $10,000,000,000 or more Subsea orders in 2025. So my question here is you booked $2,800,000,000 of orders in 1Q, 1.4 times book to bill, you’re 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. And we haven’t noted any press release orders. So 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. And do you still have confidence on hitting that $10,000,000,000 number this year?

Yes. Okay.

Doug Fertihert, Chair and CEO, TechnipFMC: So $30,000,000,000 target over the three years we’re confident in. That implies 9,800,000,000.0 for this year. We remain very confident in achieving that. In terms of the order flow, it’s a good question. These are big projects.

FID can happen on the ’30 or thirty first of a month or the first of the next month. And unfortunately, being a public company, that can affect a quarter. So it’s always hard to predict. So we don’t do quarterly. We just give annual guidance.

Our annual guidance was approaching $10,000,000,000 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, well, let me start with kind of the question about the press releases just for those who don’t 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.

Then there’s a lot of these smaller orders, most of them being direct awarded to our company, which don’t reach the materiality threshold for a press release. And it’s kind of ongoing business for us because again we’ve done decades of work exclusively for some of the largest IOCs. And they’re just on a cadence of ordering two or three of this or that per month. And that just works into our inbound on a continual basis. And 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.

So 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. So we supply all the inspection, maintenance, repair and support of our equipment over the life of our equipment.

Our equipment is designed to be anywhere from twenty five to thirty 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. So this is all done by advanced automation and control and robotics. So 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.

So now back to the cadence and how I see things playing out in particular in the near term. No announced awards this quarter. That doesn’t mean there wasn’t big projects. Sometimes our clients will ask us not to announce until a certain date. And it may be driven by reasons outside of our control.

So sometimes we’ll announce after a quarter. It’s just unfortunate, but we’ll announce the project and then say this was inbound in a prior quarter. What I will say is again very, very confident in achieving the full year guidance of the $10,000,000,000 Strong start to Q1. If I look at it, I think probably H1 and H2 will probably it’s probably not going to be it won’t be linear, won’t be exactly flat quarter to quarter. But I think H1 versus H2 will be in a similar neighborhood.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: That’s helpful. You talked about some of the longer term opportunities for FTI and some of the emerging bases growth in even the traditional bases like the Paleogene. What type of visibility do you have in terms of 2026? 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?

Doug Fertihert, Chair and CEO, TechnipFMC: Yeah, look, I don’t want to get too far ahead at this stage. But I would say when we look at ’26, and I’ll even tell you ’27, we have a robust list of 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 don’t necessarily see a plateau at this time. There’s 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 and typically are two to three years before that project ever makes it into the public domain. So because of that visibility that our clients provide to us, which we are privileged to have and humbled to have, I will tell you we remain very confident in the offshore activity. And all that I just said has nothing to do with all those emerging countries we talked about in an earlier question.

Cause they’re all largely, largely ’28 and beyond. Some you could see in ’27. But it’s what drives this thing into the future.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Yeah, next question is maybe could you briefly describe your Subsea two point zero offering? Briefly?

Doug Fertihert, Chair and CEO, TechnipFMC: Think I You want

Arun Jayaram, E and P and OFS Research Team, JPMorgan: the ground to cover.

Doug Fertihert, Chair and CEO, TechnipFMC: Well 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. And as an industry, we just accepted that.

We knew it wasn’t efficient, we knew it was disruptive, we knew it required an additional nine to twelve 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. So everybody’s 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.

So we said, okay, there’s going to be three types 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. So Subsea two point zero is just truly unique in that it’s the only way that the industry has to build something in a reliably both in terms of cost and in terms of schedule versus the traditional bespoke manufacturing way that we did, which is Subsea one point zero or which is the rest of the industry today.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Could you maybe elaborate on this concept of an integrated project? There’s projects where FTI does the lion’s share of the SURF work, but there’s projects perhaps like Suriname where I think you’re partnering with SiPEM. Give us a sense of the differences.

Doug Fertihert, Chair and CEO, TechnipFMC: Sure. So 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 Saipam, who is part of our vessel ecosystem, which is a group of companies who want to work on our IEPCI projects.

I mean it’s just really as simple as that. Remember we talked about IEPCI, the majority being direct awarded to our company, etcetera, etcetera. So those who have the vessel 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 nine to twelve 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. And we’re not done. Nine to twelve months, we’re going to keep taking time off that schedule. One, it makes us very competitive for our clients’ capital, because it’s shorter cycle.

It’s more predictable. But also, I’m doing more with the same. So 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.

And 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.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great. Subsea services is something you highlighted. You know, I believe last year you generated about $1,650,000,000 of revenue being precise here. What is your forward expectations for growth kind of in the segments? How do margins generally compare to call it your equipment types margin than just the subsea equipment?

Doug Fertihert, Chair and CEO, TechnipFMC: Good question. So the 1.65 in 2024, we indicated we thought it would grow to about 1.8 in 2025. So it’s 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’s more or less in line with that.

The profile of the business is, I guess, what’s really most interesting, and it’s these long duration contracts. So think of it kind of more like an industrial type play, a very predictable OEM. You do achieve good margins on that business. Now unlike some other businesses, don’t give away the product to get the sale, the service tail on it. We get a good margin on both, but the service margins are certainly very attractive.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Okay. Let’s talk a little bit about margins. And 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 two point zero.

And broadly talk to us on where you’re at in terms of this margin journey.

Doug Fertihert, Chair and CEO, TechnipFMC: Sure. So the margins have been expanding. It’s really been driven by the internal efforts that we’ve 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. So 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’s the IEPCI.

And it can improve the returns from the client because they’re 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. And that’s how we’re 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’re seeing the benefit, they’re realizing the benefit and then we get the benefit from our own internal efficiencies.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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.

Doug Fertihert, Chair and CEO, TechnipFMC: Sure. So look, the flexible market remains very strong. There’s three companies who do that. We’re the market leader. We continue to drive the technology development in that market.

It’s 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 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.

So they started to look at alternatives to try to mitigate that, coatings, etcetera, 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. And we’re doing that by coupling the traditional flexible pipe, which is think of it as strands and layers of steel with a peak material, which would not be porous and therefore you wouldn’t have the opportunity to have hydrogen embrittlement as a result of water encroachment. So we’re working on that. We have an ongoing qualification program with Petrobras.

We believe we have the industry’s only true SEC compliant solution. And we’re excited to bring that to the market here in a couple of years.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great, we have time for one question.

Unidentified speaker: 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 ISEP that looks when we look at the what means the engineering, it seems kind of a bit a breakthrough in order to expand into fields with higher CO2 and higher, I mean, problems with gas. So if you could talk a little bit about it, how it’s being developed and when should it start to operate?

I believe in metal 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. So it looks good, but we can’t understand what it could mean for the whole offshore industry.

Doug Fertihert, Chair and CEO, TechnipFMC: Sure. So thank you very much. And my timer is blinking red at me, so I’ll be very quick. But wonderful question. The head of our business, Luanda Dufey, is here, and she’s actually the one responsible for this project.

Look, it is a phenomenal project. It really tells, we didn’t talk much about how we develop technology, we talked about it in flexible pipe. But HYSEP’s another example. The industry had a problem. CO2 is not something that is, you you don’t want to produce the CO2 if you don’t have to produce the CO2.

So you basically, today you have to bring the CO2 to shore or to the top side. You have to separate it. You have to reinject it. We worked with Petrobras for seven years to develop a novel technology that allows us to separate the CO2 on the seabed and reinject it. It will never come to the atmosphere.

It will reduce their greenhouse gas footprint by 30%. It increases their production because it’s in a mature field and instead of producing the oil and the CO2 up to the FPSO, now it’ll be less CO2 or ultimately CO2 free. So it’s a major, major, major technology development that we did together with Petrobras and we’re very excited. Yes, it’s being used on the Mero three project initially, but we would expect that to expand and unlock other opportunities. Thank you for the question.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great, Doug. Thank you so much. Okay. We’re gonna keep things moving. Our next presenter is Murphy Oil.

Delighted to have Murphy’s new CEO, Eric Hambly, to participate in our fireside chat with us today. Even though he’s the new CEO of Murphy, he’s he’s been at the company for quite a bit of time, around twenty years, and he’s really grown up throughout the organization leading the operations since 2020. And he joined, like I said, Murphy in 2006 and has been leading the company forward since January. And the excitement here is just a few days after he became CEO, he had the pleasure of announcing a world class discovery in Vietnam. So a great and and and amazing start to your tenure, Eric.

Before diving into our fireside chat, was wondering if you could just start off with some introductory comments around the company, Eric.

Eric Hambly, CEO, Murphy Oil: I appreciate that, Arun. Thanks for having us to your conference. I think I heard today that we are at your tenth, 10 out of 10 conference from 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.

So 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, I think it sets us up to be really differentiated compared to companies that are really anywhere close to our scale. We’ll talk probably more in this Q and 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. And I think over time that will increasingly make us look a lot different than other companies in a compelling story in terms of investing in.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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 organizational strategy?

Eric Hambly, CEO, Murphy Oil: 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. And so 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.

And 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. And 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. And I’ll 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 and A of $243,000,000 The last few years we’re running about 110,000,000 to $107,000,000 So 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. So 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

Arun Jayaram, E and P and OFS Research Team, JPMorgan: able to help shape it.

Eric Hambly, CEO, Murphy Oil: So I feel really good about our organization, our capability and really, really happy of the recent success in improving our exploration organization.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Okay. Let’s dive into the 2025 program. Your budget is earmarked to spend about $1,200,000,000 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?

Eric Hambly, CEO, Murphy Oil: 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 1,100,000,000.0 and $1,300,000,000 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 and A opportunities that other people may not be able to do. So we’ll be a bit careful. But 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 that we put together, that 1,100,000,000.0 to $1,300,000,000 kind of in a typical year, we allocate about 10 to 15% of that for exploration. And then the rest of the business is a combination of sustaining basically performance of production level from our onshore business.

So Eagle Ford, we’re managing in a 30,000 to 35,000 barrel a day net to us range. Our Tupper Montney business, we’re periodically refilling to our plant capacity. And the rest of the investment other than exploration, which I highlighted is development activity for the Gulf Of America primarily. We have a steady plan of activity through the end of this decade to continue to develop our assets in The Gulf Of America, which should provide single digit low single digit growth in our business. And then you add our Vietnam new production coming online in ’26 of that, we saw little step ups over time between now and the end of the decade.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great. Well, I’m going 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?

Eric Hambly, CEO, Murphy Oil: Sure. Let me go back to the beginning of twenty twenty five. So in the first quarter, we brought online the Mormont No. Four new development well. And then in the first early part of the second quarter, we completed a workover on the Samurai-three well.

So those are already online. In the second quarter, we’re progressing workovers at Khaleesi II and Marmalard III, which should have first production in the second quarter and the third quarter respectively. And that should be the end of our offshore workover program, which as you’re familiar with, has been a bit of a sore point for us over the last few well, the last eighteen months or so. Rounding out the rest of 2025 in The Gulf Of America, we have two exploration wells planned that we’ll drill in the third quarter. They’re called Cello and Banjo.

They’re near our Delta House operated facility and with success we’ll have the ability to fairly quickly tie them in and bring them online. So 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 twenty twenty six. And 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. So that’s kind of how we’re spending our money and what we’re developing in the offshore space.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Okay. Maybe a quick update on the St. Malo waterflood project with Chevron. Where do you stand with that? And when can you start to see some production from that project?

Eric Hambly, CEO, Murphy Oil: The St. Mao 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. So the waterflood 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 waterflood performance.

We do expect throughout 2025 to start to see a contribution from waterflood project and increasingly in future years more and more of the total production will be from that. What’s interesting about sort of typical deepwater 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 San Maollow field. So the water project, while early, it’s probably starting to show some performance.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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, twelve to fifteen months you’ve had a little bit higher of a clip on workovers, but it sounds like you’ll be moving to more of a normalized level of workover spend.

Eric Hambly, CEO, Murphy Oil: I sure hope so. If we look at a typical year, we don’t 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 America business. So it’s normal for us to expect to have a year without any workover activity. We have, as I just mentioned, had a quite a year plus of quite a few high rate wells that needed to be worked over.

What’s interesting about them is the wells all had issues with different pieces of equipment. There’s not a commonality. There’s not the same type of equipment or the same failure mechanism for the well. So once we if 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.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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?

Eric Hambly, CEO, Murphy Oil: Yeah. So the Dalmatian well, we had a safety valve repair in 2024. That well has been back online and producing. The Khaleesi II 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.

So 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 Khaleesi II well was about two and a half years old. And again, totally different types of safety valves, fundamentally different designs. So fairly unusual to have something like that happen.

I think, like I said, I think we’ve turned the corner and we’ll get back to the kind of normal run rate. Our total company operating expenses when we don’t have a significant offshore workovers are kind of typically in the $10 to $12 per BOE range. And I think you should see us get to that kind of level in the latter half of the year. Okay.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: One maybe final question on the Gulf Of America. 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.

Eric Hambly, CEO, Murphy Oil: Sure. The Chinook Field, the Cascade and Chinook Fields produce to an FPSO which we purchased early this year for a little over $100,000,000 That sets us up to have a lot better accretive economics of the 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. And now that we’ve purchased the FPSO, we have a lot of flexibility in what we want to do. So 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 will likely include in our 2026 budget and will likely come online in the last half of twenty twenty six, has the potential to be pretty high rate. On a net basis, it might be up to 15,000 barrels a day. So it’s a pretty compelling opportunity for us with really strong economics. And it’s a developed field so we don’t have a lot of subsea infrastructure we have to install.

Thankfully Doug was talking about how much cost pressure they’re putting on us and we won’t have significant amount of that for this project and the timeline to bring it online would be a pretty quick drill complete tie in.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: So is that fair to characterize this more as a developmentwell versus

Eric Hambly, CEO, Murphy Oil: 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 wealth to have another take point in the reservoir to optimally produce. There was a well that was producing in that pre-twenty nineteen which had demonstrated rates that were in that range. And so there’s quite low subsurface risk in terms of the outcome.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: And I got to think and maybe I’m getting down too much in the detail, but is it EUR for that type of well, 20,000,000, 30,000,000 barrel kind of?

Eric Hambly, CEO, Murphy Oil: That’s a fair assessment, yes.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Okay, great. Great. Again, you plan to drill that in the second half

Eric Hambly, CEO, Murphy Oil: We’ll start drilling it sometime probably in the second quarter of ’twenty six, but it will take a while to drill. It’s a fairly deep well and it will probably come online in the I don’t know if it’s the third or fourth quarter, probably the fourth quarter of ’twenty six.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Yeah. We’ve had some ebbs and flows in terms of offshore service costs. Doug, who presented ahead of you, has obviously been pushing margins, but it’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.

Eric Hambly, CEO, Murphy Oil: 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 drillship we’ve been using now for a number of years out through what is our planned activity through the middle of twenty twenty seven. And 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. So we’re seeing a softening of drillships through that period of time.

And then other significant costs, so the day rate of a drillship is about 40% of the cost of a deepwater 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 etcetera 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% to 50% cost increase. So it’s a lot of pressure there. It’s one reason why I’m really excited to have some success in the 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.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great segue, Eric. I was going to ask you about Vietnam. The company reached FID on the Lok Da Vang development a little bit time ago. It’s about $100,000,000 100,000,000 barrel of gross field. Can you provide an update on this project which is targeting first oil in the fourth quarter of next year?

Eric Hambly, CEO, Murphy Oil: 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. And I’ve been very, very happy with how it’s going so far. So major milestones for the project are building the Lok DeVong A platform and building an FSO, it’s a floating storage and offloading vessel, which is basically a big storage tank with a turret.

And 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 twenty twenty six. 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. And then we’ll begin drilling development wells from that location. And then the topsides for the platform will be built in will be installed in 2026 along with the FSO in 2026. And then we’ll bring the field online.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Okay. And how should we think about kind of the CapEx outlay for this project? Because it is kind of a phased development with a couple platforms.

Eric Hambly, CEO, Murphy Oil: That’s right. So the overall development we’ll spend between 2024 and 2029, we’ll spend net to Murphy about $380,000,000 $110,000,000 is what we allocated for our budget for 2025. Next year spending is probably on the order of $90,000,000 So we’ll have first oil after spending maybe two thirds of the total capital program roughly. And then in 2028, we’ll likely install a second simpler wellhead platform where we’ll drill the other half of the wells for the development. So it is sort of a spread out capital program from over many periods and production likely peaks in the 10,000 to 15,000 barrel a day net to Murphy in the 2017, 2018 timeframe.

And then as we continue to add wells through 2029, we should see relatively stable production and then start to see when we finish drilling wells, we’ll start to see decline probably at the end of the decade.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Okay. Let’s talk about the Hai Sou Vong discovery. Again, just announced just a few days after you became CEO. Obviously you’re involved with that whole process.

Eric Hambly, CEO, Murphy Oil: 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 extremely high rate for a well in shallow water, 150 feet of water.

What we found in the well is consistent with our pre drill range of expectations for the field, which was 170,000,000 barrels equivalent to four thirty million barrels equivalent. But we don’t know now because of where the well was drilled, don’t know how much of the structure is filled with oil. The discovery well encountered only oil and no water, so we don’t know when oil water contact is. The structure is quite large. So 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 and that could help us firm up our range of resources for the field. It has the potential to be pretty large. I don’t like to get too ahead of ourselves. I’d like to see the result of the well before we say more about it. But it’s pretty exciting.

The discovery that we already are aware of from just what we’ve identified in the well is a commercial development that’s a standalone scale development that we’ll be able to develop and we’re excited hopefully to potentially prove up a larger resource with some appraisal success.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great. You did announce a discovery at Pink Hamill last quarter, maybe not the same size as Hai Souvong, but still a great outcome for the company. Talk to us about that discovery and plans to develop that.

Eric Hambly, CEO, Murphy Oil: Yeah, that’s a nice discovery for us. We expect that that field is somewhere in the 30,000,000 to 60,000,000 barrels oil equivalent. I’ll mention that these fields for us in our Koolong 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 Lakta Hong 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 tieback. We needed to find something on the order of 8,000,000 to 10,000,000 barrels to have a commercial development and we found what we think is 30,000,000 to 60,000,000. So should be quite successful there. One thing to note, PSCs that we have in Vietnam, they have ring fencing at a block level.

So 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. So pretty attractive opportunity for us there.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Good segue. How do you think about the attractiveness of this PSV versus elsewhere that you look at globally?

Eric Hambly, CEO, Murphy Oil: So the terms of the PSC in Vietnam are 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. So that might be sixty five to 75% take. The oil companies get a lot of their return early and then later on the government gets more. So it’s pretty typical of PSCs. Indonesia PSCs typically have a little higher government take, so it’s more competitive.

If you contrast that with our business in the rest of the world, obviously the government take in the Gulf Of America is like the best system fiscally in the world. In Cote D’Ivoire where we have five blocks, the government take is not much different than The U. S. It’s a little higher. So 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.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Let’s talk a little bit about West Africa, Cote D’Ivoire. E and I is at the conference. But your acreage position is bookended by two significant discoveries by E and I, Balin and Marine. And so maybe just talk about your plans and opportunities set in Cote D’Ivoire through the drill bit?

Eric Hambly, CEO, Murphy Oil: Great. So we’re going to start drilling a three well program in Cote D’Ivoire in the fourth quarter. That program the first well in the program will be Sivet, which is 10 kilometers away from the Moraine 1X discovery well on the field that they call Kalau, which they announced E and I announced in March of twenty twenty four. Geologically, the Sabet prospect is very similar to the Kalau 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 Kalau discovery goes a long way toward demonstrating a working hydrocarbon system, petroleum system. It is possible that the Kalau discovery extends onto our block. We don’t know that yet, but it looks like it from assessing the seismic data.

So we’re really excited about the prospect. The size of that Syvette prospect is over 400,000,000 barrel mean with up to 1,000,000,000 barrel upside. So something of significant scale for us. And 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. But sort of ballpark, we’re talking about $50,000,000 to $60,000,000 gross well costs, which is pretty compelling to spend that type of money and test something of a scale that could be 400,000,000 barrels plus with good fiscal terms.

The other prospects that we have planned, likely the next prospect will be one called Caracol, which is geologically similar to the producing Belen field that Eni discovered in 2021. We don’t think Caracall’s largest Belane, which is sort of billion barrel recoverable scale, but it does look very similar. It’s fairly close by, has the same age reservoir and the same sort of geologic features. So 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. But again, large opportunities with low well cost, we’re really excited about that. And 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 Cote D’Ivoire, the sum mean unrisked resource of those opportunities is five times the size of our current offshore proved reserves. So with success in any of them, it has pretty material impact to our company.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: The market will definitely be well watching regarding Murphy.

Eric Hambly, CEO, Murphy Oil: I’m pretty sure our share price will go down if we announce a discovery because of concerns about additional CapEx.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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 exploration with West Africa?

Eric Hambly, CEO, Murphy Oil: The exploration team we have assembled has a diverse set of experience of quite a few basins around the world. You know, we typically have most of our senior technical hiring is from people that work at super major or other type 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. So 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 America and West Africa.

And so we’re really well positioned for executing a nice program there.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: 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?

Eric Hambly, CEO, Murphy Oil: 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. So 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.

We’re in parallel with that negotiating with various Ivorian government parties around the gas sales agreement. And 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 doesn’t happen. In the country, Cote 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 Belane, 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 fifty fifty at this point.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Alright. Sorry to ask you this question, Eric, but we’re the last conference before 2Q earnings season’s here five days away. How are you feeling about 2Q? How the rest of the year is kind of setting up for you?

Eric Hambly, CEO, Murphy Oil: 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. But I’m pretty happy with how we’re executing both offshore and onshore.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Great. Why don’t we cut it off there? Thanks, Eric.

Eric Hambly, CEO, Murphy Oil: Thanks so much.

Arun Jayaram, E and P and OFS Research Team, JPMorgan: Appreciate it.

This article was generated with the support of AI and reviewed by an editor. For more information see our T&C.