Good morning, everyone, and welcome to this first quarter 2025 result announcement from Archer. Today we have the pleasure of having CEO Dag Skindlo and CFO Espen Joranger with us, who will take us through the report. Dag, the word is yours.
Thank you, and good morning, everyone. Thank you to Arctic for hosting the streaming today. I will today go through the first quarter 2025, give you some color on that, and try to take questions along or at the end, I think, you know. Please, please feel free to ask questions. The usual forward-looking statements, warnings. Before I start, I think it's important for us to say the highlight for us in Q1 is that we start paying dividend. Now we have confirmed today that we are starting to pay dividend, about $5.5 million now for Q2. It's a direct yield of around 11%, a little bit above the share price today, but it's really a testament to the job we have done in the last few years, growing the business, growing the EBITDA, but most importantly, growing our cash contribution significantly over the last few years.
We have refinanced, and now we are able to pay dividends. I know for a lot of shareholders that has been a long, long journey, but now we are here, and we are confident that we will continue to pay dividend and that we have a good cash flow going forward. Just to remind you all, Archer typically well services and drilling services. We are a well company. We focus on the well. We are about $1.3 billion of revenue, and we are about 5,000 employees. We are operating about 40 locations globally. To the financials first, we have, as you can see, grown quite significantly the last few years. If we meet our guidance for this year, we will have grown about 24% since 2022 in a mix of organic growth and through M&A. I think that's quite good.
We have a target this year to grow EBITDA by 15%-25%, and we reiterate that guidance today. Leverage ratio has come down significantly in the last few years. We are now targeting about between 2.1% and 2.3% at the end of the year. We have our long-term target to go between 1.5% to 2%. Also, and maybe the most important number is the cash contribution, which we expect to be well above $100 million in 2025. On our businesses, our biggest business is the well services and platform operation business, o ur core business, historic business, represents about 75% of our global EBITDA. Platform operations is where we operate our clients' drilling facilities, maintain them, and secure that they drill the wells they target from their production platforms. Just as a reference, we drill about 20%-25% of Equinor's global wells every year.
Well services is the most versatile and global business we have. About 60% of the revenue is outside of Europe, so it's a global business. We have conveyance, coil tubing, and wireline, and we have a broad portfolio of down-hole tools. We focus typically on maintaining the wellbore or the old well and closing it down. That's our focus. That's where we maybe separate a little bit from many of our competitors. Renewable services, we launched that in the last few years. We now have a business of around $100 million plus of revenue this year. We have about 10% EBITDA margin, and we are cash positive from our renewable segment. We are very pleased with that. We think we went in at the low- entry -point and low -risk, and that's where we want to be. We want to build a service industry, not necessarily take big technology bets.
Land drilling, come more back to that, but we are the largest land driller and worker company in Argentina. I come back a little bit more to some details around that later. That's Archer, $1.3 billion of revenue, good cash generation, quite a globally spread operation. First quarter, I think it's important to highlight we had good growth. Revenue is up by about 11% since last quarter last year, and EBITDA 9% since last year. I'll come back more to that later. That's a good growth compared to where the rest of the oil service industry is seeing what the growth in that period. Same, you see same trend for revenue and EBITDA last 12 months. Key part, we refinanced in Q1, as most of you know. We have a new $425 million secured bond, senior secured bond at 9.5% coupon, five years maturity, which then matures in 2023.
We mentioned already the cash distribution of $5.5 million now in Q2. We have won a number of large contracts since the end of the year. I'll come back more to each some of them afterwards, but really it underpins that we are growing, we are winning contracts, we get visibility on the years ahead, and we are deepening our relationship with our customers. We do more scope than we have previously done. We are succeeding in our drive to deliver larger projects and longer projects for our clients. That is the key part for our well services division is to move into the long contracts, not so much well -to -well and competition on frame agreements.
Here, as we said, today, if you look at the share price, that is yesterday morning, I think it's around 11% and probably this morning too, around 11% direct yield. Quite well positioned versus the larger competitors. You know, we have on the pair two, three, four, you know, we have the typical large one with Schlumberger, Halliburton, Baker Hughes, Weatherford, etc. On the right, pair one is another competitor, a Norwegian competitor of ours is having the highest yield. We think, you know, this clearly probably illustrates that, you know, we have a good cash, you know, trust that we have a good cash flow generation. Secondly, probably that you could argue that our share price is somewhat undervalued based on that cash flow. Very happy with that. I think if you're on 28th of May, all shareholders will get their first distribution from Archer. Very happy.
Want to reiterate a little bit also on the position and why we are a little bit different from many other oil service companies. We are positioned in what we call the brownfield and the late life space in the oil service sector. This means that this is areas where the platforms and infrastructure is built. This is OpEx-driven decisions. This is where the oil company generates the cash flow from their production in brownfield. This is where they take the cash they generate in brownfield to invest in dividend to the shareholders, buybacks, and their investments into greenfield. This is where the oil companies, our clients, take their money from to fund that. We have many, many years. This is the lowest cost per barrel. As long as the marginal cost is lower than the marginal revenue per barrel, they will keep operating this.
We see a long time within the brownfield operations for decades to come. This is also according to our clients' plans. Also, if you look at the energy transition, this is a focus on P&A and decom. We have a growing market for at least the next 25 years. Our job is to take the biggest portion of that share that we can take. That is why we have the strategy to gradually transition off to production assets to do the big scope of decom and P&A. Lastly, we have a service in renewable services, and that is a good place we are. We do not plan to invest very much more at this stage, but try to see how we can grow that service business over time.
You know, if the oil price really, the oil service really comes down, I'm sure renewable will be a very nice place to be because we need energy from somewhere. A little bit about the financial history of Archer. You can go back to 2017. You know, we were at the 7% margin, about $55 million of EBITDA. If you look at the updated guidance for 2025, we will be around 12% EBITDA margin this year and generate between $155 million and $170 million. Quite a steady growth over time. I think we all had a hit from a good growth into 2019, and then COVID-19 hit us. It's not so easy to see it when you look at Archer's financials, but you can see it. Actually, our well services and platform operation had increased EBITDA in 2020 versus 2019.
The impact for us, the 1% margin drop into 2020 and 2021 was linked to the stop in activity in Argentina, which was severely hit by COVID. This illustrates a little bit of how resilient we are to oil price changes. No one will argue we are totally insulated or nothing can happen and all our clients are spending the money, but relative to everyone else, we are very well placed. I think you can see over here where we're taking the five large well service companies in the world, Schlumberger, Halliburton, Baker Hughes, Expro, and Weatherford. You know, if you look at their change from the same quarter last year, sorry, they had from Q4, they are down by 24% in average on their adjusted EBITDA. We on the report EBITDA is down by 8%.
To look from a year ago, the average is down by 12%, and we are up by 8%. It does not reflect necessarily that we are better or smarter, but we are differently placed in the cycle. We are less exposed to some of the countries and some of the greenfield that our competitors are exposed to. You know, we do not have much exposure to Saudi. We do not have much exposure to Mexico, etc. We do not have much onshore. You know, if you pick those big ones, they all have big exposure to some of these places. We do have some exposure in the U.S., but quite limited compared to the rest there. We think we have a good track record in the short term and the long term of actually delivering stable financial returns.
That also gives us the confidence to keep our guidance and keep believing that we're going to grow next year as well. I always talk about the P&A market. Why? Because it's growing. It's doubling in the next 25 years. The biggest market is actually our home market. So 5% of the global market is our home market, Norway and U.K. U.K. spending today, if you look at $30 billion in a five-year period, the industry is spending $6 billion on decom globally, offshore decom. About one third of it is in the U.K. alone. If you look at Norway, Archer is executing the only large platform P&A contract in Norway. It's the start for a platform. That's Archer managing the whole operation on behalf of Equinor in terms of drilling, well, and all the well services.
We are managing a project that is going to finish, I think, in summer 2027. We had just been awarded the only large subsea P&A project in Norway, which is with Equinor. We will come back to that later. Similar in the U.K., we are just finishing off TACA. We are working on Fullmark, the first phase of Fullmark, the project with Repsol. We got the large contract now for 130 wells with Repsol on a seven or five plus two-year contract. We are definitely a leader in our home market. We are expanding then into and focusing on some of these growing markets. Some technologies are very relevant. I will come more back to that. Of course, we are early into some of these areas. You know, deep water Gulf of Mexico has not started. It is probably going to start 2029 or 2030.
The position and grow the service gradually and track record and reputation in that market for the clients is very important. That is why we bought WFR last year. I think either in Q2 or Q3, you will see one nice announcement for us where we are winning a P&A project in the Gulf of Mexico. It is also interesting to be a little bit in Gulf of Mexico on the shelf because what is happening is what we call the boomerang effect in the U.S., where BP and Chevron and now also the rumor goes on Exxon is getting back like 500 wells. You know, they sold off, like, acreage to smaller companies that went bankrupt and now they are having them back. If it was the smaller companies operating and closing down the wells, we would not be a service provider. It is quite a cut-throat basic services.
When you have the majors being part of those campaigns, there are also interesting bits of pieces of work for us. We are actually through WFR doing the cut and pull, which is a part of the P&A campaign for BP's 300 assets. We are involved in the business and we need to grow that business. These are some of the major contracts. I'm not going to go into details on this slide, but really we have the, as we said, the P&A contract. Just to understand that, it's about $150 million. I think Equinor announced NOK 1.8 billion. We say $150 million , you know, that they expect us to do. The only two companies who got awarded that contract, that's going to be a subsea P&A supplier to Equinor according to the awards, are Archer and Baker Hughes.
Schlumberger did not win anything. Halliburton did not win anything. And Weatherford did not win anything. And Oilfield Technology did not win anything. We are, you know, the guys that are leading and our job is to lead, continue to lead. I think the game is heating up and people are taking notice of the work we win. I think we have quite a strong drive also from the majors to get into this space. Fishing contract in Gulf of Mexico. I think to head the hair is not a big deal to say that it was Shell, Shell Deepwater Gulf of Mexico. This is the $50 million contract for WFR that we got announced. The Repsol contract, I'll come more to that. Also the Pan American, I'll come back a little bit to later.
A lot of contracts underpin the growth, not only this year. You know, the subsea P&A is for 2026 onwards for execution. The contract for Repsol really starts more towards the end of the year and will be next year and the year after and the year after. We are adding to activity from our existing activity level. Yeah, a little bit more on the subsea, just to be clear, you know, we got awarded 27 wells as a scope on Hedun and Snorre. It is quite exciting for us. Equinor gives us a lot of responsibility all the way from well engineering to planning and offshore execution. Before, most companies only get to do the offshore execution and their portion of the offshore execution.
Our joint venture with Elemental allows us now to take the bigger contracts and try to integrate from well engineering all the way to technology and execution. That is a very important part of the sales process we are doing now, to bring technology and solutions very early into well engineering. Because if you do that the traditional way, well engineer really prepare packages for procurement the first, you know, six or nine months, and then they go for procurement, and then they get all the feedback, and then they finalize the engineering. We can get all the right information about the best way to abandon the well from the people who do it offshore and have the technology right in the first time, and you cut the period quite significantly, and you can optimize the execution.
I want to mention that maybe it's a bit technical, but on that FLX project I talked about, start for day, Equinor had in their own planning planned to spend 900 days on that program. When we work with the planning and technology and solutions, we qualified three new products that we could use for 21 of their wells, of their 30 plus wells. We developed a total new product for them, and we convinced them to buy a pooling unit. That reduces the number of days that Equinor is going to do to about 600 days. They go from 900 days of a P&A activity to 600 days if you plan it well with the right technology and the right people. That's the opportunity cost that traditional model will not give you. This is what we try to sell to our clients.
It's quite convincing, but it's quite hard for them to buy. It's easy for Equinor because they have so many contracts with us already that they can just award it as part of the contracts you already have. To go for these tenders is not so easy for the oil companies. This is a part of our job is to change the way they buy. I think subsea is, you know, as I say, it's a new revenue stream for us. We haven't really done subsea P&A project before. It's hardly been done any subsea project, to be honest with you, in our own core, done some other places in the world. This is kind of also a new revenue stream for us. We've been focused on the platform P&A.
Now we're moving into the subsea, and we have quite a few technology solutions coming up that we think is going to set us in the forefront of subsea P&A. When I say subsea P&A, it's basically you don't have the platform and a rig, a platform to drill to do the P&A. You have to bring, typically for subsea P&A, you have to bring a floater if it is deep water. You know, it would bring us a semi or a drill ship. And you can imagine what those costs are per day. If you can optimize and reduce the number of days it takes, or which what we are working very hard, and I think so many industries are working very hard on, is to take that scope away from the rigs and do more and more on the vessels. This is going to happen.
We are confident. It's just a matter of how fast it goes and how it develops in the different geographies because clients have different risk appetite for what they want to do and how they want to abandon the wells. The regulation is different from different places in the world. If you go five, ten years out, I'm not sure how much rigs will be used for P&A for subsea wells. Yeah, really what we've said all the time, Archer, you know, production area, brownfield, late life, and P&A. Like on Repsol, we have the platform drilling contract today. Really for platform drilling, platform operation is not a big change. It's just continuation. We had two more years, I think, Espen, on the current contract. Now we got five plus two. We have extended that contract.
The big thing is today we do not do hardly any well services for Repsol. Now we are going to do all the well services that we have: conveyance, coil tubing, wireline, and all the down-hole tools. This is a growth. If you go and look into our financials for next year, we should start seeing the benefits of this contract. Again, this is what we have been telling our clients for some years now. We want to industrialize the process. We need to streamline it. It is all about the cost, drive down the cost for the operator. You can win the work. You need to be cost-effective. It is not about expensive new technology. It is not like for a new well where the most important part is how much oil you find and how you can produce that most efficiently. Can you increase your recovery factor?
It's extremely important to have the right solutions. You are willing to spend a lot of money to get to the reservoir the right way with the right production profile on your well construction. On P&A, you just want to do that as cheap as possible within the regulatory framework. A little bit about Argentina. Let's talk about the south first. As we have said always, there are two areas in Argentina. You have the south, very conventional, where you basically drill horizontal wells. Sorry, sorry, vertical wells, only vertical wells. Very mature, lots of issues, very marginal for our clients. Has been marginal, I think, for quite some time. Know that they need to spend the money on your new wells in Vaca Muerta. As we say, you know, they put $1 down in Vaca Muerta and get $2 back. Probably in the south, you put $1 in and you get $0.80 back.
That's why they're reducing the activity in the south. It's not as black and white as I tell. Of course, there's different areas there as well and different. This is the problem. We have, through a lot of discussions now with our clients, reduced activity quite dramatically. We'll take out about $75 million of annual revenue from our roughly 5% of our global revenue. About 20% of the revenue in Argentina is going to be reduced going forward. We're doing all the restructuring now in Q1 and the most now in Q2. I think we more or less finished all the reductions. We have actually reduced the headcount by more than 500 people. The good news, this was a margin business also for us. Now when we take out that business, we reduce our maintenance CapEx, we reduce our indirect cost.
Going forward, it's not a negative. We actually just reduced our continued liability in the country. For us, it's very tough, of course, to have more than 500 colleagues go home without work. We had a good relationship with our clients and our unions and the government. In the end, most of these expenses were paid by the client. Actually, Pan American decided to pay 20% more than their statutory had required in order to get it happen quickly and with as little unrest and challenges as possible. It is a constant negotiation between us and our clients and the government how to do these type of big changes. We came out very well as InCare. I'm very pleased with the end result. Of course, it's a bit uncertain when it happens and so forth on, but we have the experience.
If you look at our business going forward, Vaca Muerta is going to be a lot of drilling in the next three, five, ten years. The investments in pipelines are taking, unfortunately, in the short term, a lot of the cash flow from our clients. They're building oil pipelines. Soon they will have the ability to, I say, one million barrels share per day. That's the increase. Really, it's one and a half. The new pipeline, just the one pipeline, has the capacity to one and a half million barrels export per day. They're now signing two agreements with Golar for two FLNG vessels that will come. The first one will come already in the end of 2026. We believe that towards the end of this year or definitely next year, there's going to be high demand for rigs.
Right now, the oil companies are holding still quite the tight lid on the activity. They've added a little bit of capacity, but they are basically spending their cash flow on the pipeline rather than increasing the drilling. When they have sight of, you know, line of sight for the end date and the contract dates, they will ramp up the drilling. That is a very good area to be in. We are very confident. If you look at the financials, you know, in Argentina, as we said, you know, 55% of our revenue going forward is in Vaca Muerta. 85%-90% of their and the cash flow comes from Vaca Muerta. Again, it is a very marginal business in the south of Argentina. The bond, I'm not going to talk too much about that. We presented that quite a few times before. Very happy with that.
We upsized the bond. We had good investors, long-only funds coming in and giving us a good horizon on our maturity. We will mature in 2030. We agreed to also do some amortization through the way due to our discipline in a way. We wanted to show that we want to reduce our leverage. We can pay our interest expenses, we can do the amortization, and we can pay dividend, and we can do a little bit more deleveraging depending on the investment opportunities we get either in companies, M&A, or in good growth assets. You know, we have, I think we have enough room to balance those factors. That gives us a lot of comfort that we are not going to go out in the market yesterday or in the next three months, you know, with all the uncertainty in the world right now.
Guidance, I think we have talked about it already. We're guiding down. As I said, a lot of that is from Argentina. The $75 million annually, it comes from Argentina. That's quite a lot. We have less reimbursable and also a little bit of the small changes. In overall, it's really we're maintaining our MTR. We have some ups and downs. We have some downs in Argentina because of redundancies. We are taking some of that cost. From a cash flow point of view, we are quite, quite, quite well organized there. We update guidance a little bit on CapEx, but it's important to say, and I don't think it's clear for everyone else, we are basically reducing maintenance CapEx in Argentina, and we are replacing it by growth CapEx for all those things. That will benefit us next year and the year after.
It is better CapEx spent now. If it is more, it is at least not maintaining all the asset that did not really give much of a return. Now we can put it into asset that has a high return on capital with short payback. That is the switch we are doing. Guidance $2.1 [billion]-$2.3 [billion] still at the end of this year. I think Espen will tell us that we are in the midpoint. That, I guess, assumes, Espen, that we keep paying dividend for the rest of the year. At this level, I think that is a fair assumption. Last, just to remind everyone, we have, and I think we have shown that, a very resilient business model. We have seen steady growth since 2017 - 2025. Margin steadily growing, not really impacted that much by COVID-19.
We're not going to say we're not going to be impacted of a big recession or an oil price of $40, but at $50 or $55 or $60, Archer is still going to do quite well. You know, we can manage that activity, that oil price level. We are refinanced. We're paying dividend. If you look at the yield right now, I think it's one of the more attractive yields that you will find out there. We at least are confident, and I think the board is confident, and I think the main owners are confident that this is something we can continue with. You either buy the share because you want 11%. I shouldn't use the word guaranteed because it's forward-looking, isn't it? You know, a good return with quite high visibility on it.
Or hope that also you can get it faster with the share appreciation. We are reiterating our growth. There is a small mistake. It says 2005 on the bottom there. That is a mistake we noticed this morning. That happens sometimes when we are in different locations, and this goes a bit fast in the end. Hopefully you can excuse us for that. I think the one that was published, Alan had 2025. That was really all for today. Espen, do you want to come up in case of questions?
Okay, thank you, Dag. I think we can start with questions starting here in Oslo with the audience being present.
I can take the first question. Working capital had a little bit of an unfavorable development in the first quarter after being quite strong in the fourth quarter last year.
Can you give us some background on what happened in the quarter and how we expect that throughout the year?
Yes, that is mainly explained by two items. It's the days outstanding on accounts receivable. As you said, they were very strong in Q4. We had 47 days outstanding in Q4, and we're up by five days in Q1 to 52, which is more the normal. Between 50-52 days outstanding is the normal on the accounts receivable. I think that explains the large portion of the increased working capital. The other part is that we invested in some inventory items for growth outside internationally in well services. Those two are the main explanation on the increased working capital in the quarter.
Just to have said that, you know, we build like close to $4 million in average per month per day, you know. The contracts are and the wells are finished, you can build typically, you know, okay, on, let's say, in Argentina. The days outstanding can fluctuate quite a lot during the month. The data point at the end of a quarter is quite incidental, to be honest with you. If it is 48 or 50 or 52, it has no underlying reasons to be high or low. It is just some bit of timing. We have no bad debt. We have not had any bad debt in Archer since we started. I think since I started, we probably written off $500,000 or something in the nine years. It is not a trend or anything that you should expect.
I think it was a lot of clients actually paid early in December. Now we're a bit unlucky on the end of the quarter. I think you will see probably on the 50-day or something as an average is a good number.
When it comes to 2026, it's obviously early days still. For 2025, you say that you expect a ramp up in the second half of the year. Based on the visibility you have today, is it fair to assume that, let's say, second half 2025 represents a run rate for full year 2026?
You know, as you know, Martin, in this world, 2026 seems like, you know, far away. I think what I can say is that we will have a good, we think we have a good backlog and visibility that this will continue into next year as we see today.
Remember always, Q1 has less days. When you see everyone reporting not a run rate in Q1, that's how the business is. You know, it's less days. Let's say for us, that is a lot of a day rate business. You know, all the drilling and all the platform operations are day rate business. As soon as you lose one day in a quarter, you basically lose $3 million over there, $3 plus million over there. Q1 will always be weaker. In addition for Q1, you always have the Norwegian winter that typically is a little bit less than in the summer. Secondly, you have the summer vacation in Argentina in January. Q1, if you look for us, is always a bit weaker.
By the time you get to Q2 and Q3, we are back, we think we are back to your new run rate, Martin.
Thanks.
You presented some one-off costs in Argentina this quarter. Is this something that will continue? Will we see any more one-offs as a result of the news flow there, or how should we think about this?
You will see some more one-offs in Q1. I'm sorry, Q2, as we finalize the, it's still a little bit uncertain how everything will be accounted for because, again, there's a lot of different charges that go to our clients to get them to pay. It's a little bit of accounting technicalities. Yes, we have some exceptions also in Q2, but we also think we might have some exceptions on the positive side in Q2.
If from a cash flow point of view, you will not see that effect because we are also selling some assets to our clients to pay for it. That is how they are partly funding it. They are partly funding it directly and also partly through some asset sales. Understood.
It is fair to say it will be less than what we have in Q1.
Yes, that is correct.
Okay. In terms of, I mean, this was not relevant for this particular quarter, but has there been any changes in sort of your ability to extract cash from Argentina?
No, we can take out cash. We have done that. I do not know how much we did in Q1, Espen.
$2 million.
Yeah. We have a plan for the year, as we said, but more than $10 million this year to take out. We have a special ambition of $15 million.
Let's see what we are able. It's not going to be because of capital restrictions. It's more our cash flow from the business. Not that we are reducing it and we have to fine-tune the, but we still have the ambition to take out $10 million-$15 million this year. There's no restrictions.
Thank you.
Okay, we can take some questions from the webcast as well. Can you clarify why the revenue guidance was lowered while the EBITDA guidance was maintained?
First of all, as we said on the reduction, a big portion of reduction, about $75 million, comes from Argentina, where we basically have very low margins. Then the mix changes a little bit. Yeah. Secondly, the mix of what we see on the product sales we have and the forecasted product sales helps on the margin side.
Then reimbursable, there is also less reimbursable in our forecast right now based on client activity, where we basically have zero margin. When the revenue falls, it does not change the EBITDA on reimbursables. It is a very marginal, you know, impact on the revenue we are losing. It is not the good revenue from well services on good product sales or anything like that.
Okay. Have you taken any precautionary measures to address any potential slowdown in the market?
Of course, in Argentina, we are taking quite drastic reductions in the whole structure, you know, the whole indirect structure, the investments in equipment in the south of Argentina. We are quite up there. At the same time, we continue to grow. Yeah. We have quite good visibility, and that is also why we have increased our CapEx.
Of course, in the U.S. onshore, the small business we have in the U.S. onshore, we are more careful. They are not buying any CapEx, or we are holding the headcount, let's say, not to grow, and we are watching it, I would say, as you have to do in U.S. land. People can say from week to week, but maybe from day to day when you receive your letters from your clients that they want to reduce the rates. Really, we are lucky. We are with a major also onshore in the U.S., and so far they are largely holding their activity. We actually had a very good month onshore in the U.S. in March, which was a bit counterintuitive, but sometimes it is just the number of wells that they get problems with and they need the services from us more than the market.
I think overall, we are watching very carefully. I think the good thing in Archer, we have always had a very low overhead cost structure. We have always been mean. We always have the ability to cut CapEx and investments if the activity is not there. We have shown historically we are able to do that. I think that is where we are. We are quite confident at this moment. Okay. Next question. Could you give an update on the startup timing for the Emerald? I cannot give you that. We are in negotiation with our clients, and we have not quite decided that with them yet. I think I should not say that, but I think if you, we have our, you know, assumptions for the full year, we know what we have there, and we are quite well balanced in what we think.
Okay.
Regarding the two FLNG vessels in Argentina, what impact do you think this will have on drilling demand in Vaca Muerta?
You know, if you believe Ristad, I think we're going to have double the rig count by 2030. We are more, you know, we probably think it's going to be 10-15 extra rigs between 2026 and 2027. That's our local estimates. When they build the pipeline, there's no way the oil companies are not going to fill them. The question is just how many rigs, and I think it's not only about the capacity of the pipeline, it is also when they phase them in in terms of our cash flow and what the global market is in terms of oil prices.
Our estimation is that this is supporting what we have said all along, that probably by 2026, 2027, we will have another 10-15 rigs added in the Vaca Muerta field. If you look at just YPF, if you look at their investment presentations, they alone are estimating 10 next year. We do not think they are going to do 10 rigs next year. That is our view, but let's see what happens. I think that shows there is clear need for more rigs in the country.
Do you have any rigs that you can add, or would you have to buy them first or build them first?
We will not build new rigs or buy new rigs. You know, a new rig like that is a $30 million-$35 million investment. I would say we have two rigs we can upgrade.
They're not ideal, but that is a possibility depending on how tight the market gets. We can upgrade those two rigs. We are in discussions with two international drillers to lease those rigs. We'll see what comes out of that. That's a way to grow out for us without investing more capital.
Okay. Next question. When do you intend to repay the RCF?
You mean the clean down on the RCF?
Yeah.
The RCF has like four and a half years maturity. I think we have the overdraft that we use for seasonality. I think that, as Dag said, that will have a clean down in the agreement. That will happen. We haven't sort of planned for when it will happen, but for sure we will do that according to the requirement.
Okay. Next question.
Can you provide guidance on dividends for the remainder of 2025?
I think the expectation is that we will continue at the current level, that the board will approve the same level in Q2 and Q3. We will continue at this level. As everyone here knows, that is a discretion of the board given the situation at any point in time. I think the board would not have started at this level without seeing that that is something that is sustainable and that we can continue on. The idea from the board and the owners is that we can increase that over time as our earnings increases.
Okay. There seem to be no further questions. Thank you very much, Dag and Espen, for the presentation. I wish everyone a nice day.
Thank you, everyone, for joining today.