BW Energy Limited (BWE) Earnings Call Transcript & Summary

Okay. I think we will try to make it timely start, because we have webcast going. So a warm welcome to this first quarter 2025 and Maromba FID, the long gestation period is over, presentation by BW Energy. This presentation will be hosted by Jerome Bertheau, our Chief Technical Officer and in charge of the Maromba project; Thomas Young, our Chief Strategy Officer who is here to present the financials we have, or the project financials; and then Brice will round up the presentation and complete the quarter. We also have some key people from the Maromba, not only project, but involved in our Maromba development, our Brazil office. So we have, and if you can raise up when I say your name, that's fine. Alex Almeida, he's our regulatory responsible for Maromba and Brazil. We have Chris Boyers, our Subsurface for Maromba. We have Thomas Kolanski, our Chief Business Development Officer. We have Kei Ikeda, who's responsible for the FPSO refurbishment. And last but not least, Ricardo Mucci, who's our GM in Brazil. So please ask these guys questions. I know, there's some questions around regulatory process, et cetera. Please benefit from having these people here and ask questions after we've finished the presentation. Then please note our disclaimer as usual. So highlights for the first quarter. We recorded a quarterly EBITDA record, very pleased with that. We had a $74.8 per barrel realized oil price. We may not see that next quarter, but still, it was good to have such a quarter. We had a net production of 36,000 barrels per day, which gave us 3.7 million barrels sold in the quarter. And we made a substantial oil discovery on Bourdon. So the other highlight is, of course, the Maromba FID, which we're going to present today. And we had a very solid cash position of close to $287 million. So the key figures for the revenue, we were suitably up on the first quarter last year, 55%, $282 million, and also up on the fourth quarter due to improved production regularity. We had EBITDA of $182 million, also significantly up, and net profit of $83 million. And we had an operating cash flow of $155 million, also significantly up on first quarter '24 and the last quarter. We have a diversified asset base, and I am particularly fond of these numbers. We have close to 600 million barrels of 2P+2C reserves, which to me talks to that we have a long horizon in front of us. We have 230 million barrels of 2P reserves net, and we have 10 operated fields. We're also involved in one non-op operation. Last year, we produced 10 million barrels, about 27,000 net barrels per day, 10 million barrels. But that gives you a kind of perspective on the longevity of our business, I think. And it's a pretty good resource position for a company our size. So our production increased in the first quarter. Very good regularity on all operations. And of course, we then could also note a reduced unit cost, mainly due to the increased volume, but also some increased efficiencies in consumption of natural gas, diesel, fuel, et cetera. We had another reasonable quarter in terms of environment. We had 0 lost time incidents, but we did have one environmental incident that was a spill of drill fluid due to equipment malfunction. It's been, of course, notified to the local authorities and dealt with. Then on to Gabon. Dussafu production was 2.6 million barrels, up 3% from the fourth quarter. Very good regularity, as I mentioned. And we had all production wells online, and our operating costs reduced to just below $10 per barrel. Please note that, we have changed the reporting regime. We are excluding some royalties and tariffs, and this is to be in line with what is common when you report costs per barrel. So we have a break in our reporting. So if you look for numbers across, you will see that, but it is because we are now more in line with what is usual in our business. We had a very good turn on Bourdon with a nice discovery. We have discovered very good reservoir, and we have the best fluid quality of all the Dussafu discoveries so far. So we're very pleased with that. We drilled 3 penetrations, 2 into the main reservoir, and we are very confident with what we have found. So we are going to very shortly start the process of planning a development similar to what we have done on Hibiscus/Ruche, and the initial plan is for 4 wells. But of course, we are now fast tracking our understanding of the nearby bumps as well, to see or to map out an appraisal program that will go along with this development. So very exciting and again, bodes well for Dussafu and continued success there. Then on to Brazil. Golfinho also saw a good increase in uptime, and we were up 12% on production to 600 and close -- 56,000 barrels per day. Operating costs came down a bit to $42.2 per barrel. We had -- we had an unfortunate shutdown of Petrobras gas supply due to maintenance, which affected previous quarters, but this was -- that was completed, and we now have full gas supply again. We will, with the FID-ed Golfinho Boost project, now focus not on drilling infield wells, which was our original plan, but on making incremental improvements in the production facilities to increase uptime, also reduce gas consumption and install subsurface ESP skids, mudline ESP skids. That will increase the production from the existing production infrastructure. So the target is about 3,000 barrels per day and releasing about 12 million barrels of additional reserves. The investment is calculated to about $100 million, and we have a breakeven of this investment at $47 per barrel. So we think it's a very attractive project. And then on to Namibia. The Kharas appraisal well planning is going well. We are currently in negotiations with rig owners about rig availability. We talk, of course, also to our peers, and it's of course, good to see that people around us are still making discoveries. So Rhino just announced a sizable discovery just south of us. So that's good. So our process is tracking well. Our long lead items are in -- or will be in-house by June. So we are ready to go in the second half. Some uncertainty on to exactly what rig and rig availability. So we may be third quarter, we may be fourth quarter. We don't know yet. It depends on the rig that we choose in the end. So we had a very accretive start to 2025, the Bourdon discovery, the Golfinho Boost FID and then the subject of this presentation from here on, the Maromba FID, which will be a transformative project for BW Energy. We expect the project to yield about 123 million barrels of 2P reserves. We target first oil end of 2027, and it has an exceptional IRR at more than 30% at $60 per barrel, flat forever and a breakeven of $40 at 10%. It will deliver a doubling of BW or more than a doubling of BW Energy's net production. So it's a super interesting project for BW Energy, and will have material impact on the company. The concept we have finally been able to develop after quite a bit of back and forth. And that's been mainly caused by swings in the market, what is available and at what price. The new concept, we benefit from the availability of large jackup drilling rigs capable of operating in the water depths of Maromba. So the new concept is based on a jackup that will be converted to a wellhead platform with drilling, full drilling facilities. The development will consist of 6 plus 6 wells. The first 6 will go in and will give production to underpin the investment in the infrastructure. But the real objective is to -- in the second set is to also appraise the other resources that are available in the Maromba concession. Again, just to remind you, we have 100% working interest. Our target is a plateau production of about 60,000 barrels per day. And the total CapEx, that's including the 12 wells is $1.5 billion. The Maromba was discovered back in 1980. When it was discovered, it was hailed as one of the biggest discoveries of its decade. So it was a very big thing when it was found. Petrobras and their partners drilled 9 wells, 8 found oil. And they made 5 penetrations in what is called the Maastrichtian. It's a very well-defined sand, and it's been highly appraised and delineated, as you can understand, by all these penetrations. They also carried out 2 drill stem tests where they confirmed the reservoir quality and the productivity of the wells. So what we are addressing with the first 500 million barrels is very well defined, very well proven reserves. And that's going to underpin the development. But there's a lot more in the Maromba concession. There's underlying carbonates. There's a lot -- there's Lobo and a number of names on secondary targets. And the concept we have developed, and that's why we're so pleased with this concept allows us to unlock this potential in addition to the Maastrichtian. So the Maastrichtian in itself is a super world-class project, which you will hear much more about, from the later presenters. But the price is, of course, to unlock some of these additional reserves. So the first phase is the Maastrichtian, the focus on Maastrichtian, 6 wells, plain vanilla, get production going. And then we have the capacity to drill and appraise and infill, et cetera, to really benefit from the resources. The potential is significant. We have -- the estimates are around 1 billion barrels of oil in place. So we can maybe not multiply by 7, which we have been able to on Dussafu. That would be great, but maybe not realistic. But if we -- we do definitely have a fantastic runway. So the future is to unlock these reserves and create very much the same type of dynamics that we've had on Dussafu. So with that, I will hand over to Jerome, who will take you through the project. Thank you.

Good morning. So I will take you through the various aspects of the Maromba project. So starting with the field layout. So we intend to deliver first oil in 30 months from today. And we will be using a wellhead platform, which will be repurposed jackup, as you see in the illustration. And it will drill the wells and as well support the production during the 20 years of operations. The production will be then routed to the FPSO Maromba, which will process the oil, gas and water and store the oil before it's offloaded. We intend to use the DP shuttle-tankers for the offload due to the weather condition in the Campos Basin. So if we look now into a bit more details. So the wellhead platform, as I said, is a repurposed jackup. It will hold 16 slots. So we will be able to drill our 12 wells, but there will be some spares for future development and for future upside. The idea of the jackup will also be to support the ESP change out when we are in operation with the derrick. And when we won't have any more development, we will replace the derrick by hydraulic workover unit. So it will host all the personnel to drill. So it has 140 POB living quarter and it will be converted in a shipyard. We are actually tendering it now. All the production from the wellhead platform will be transferred to the FPSO via flow line. So it's a 10-inch and 6-inch flow line and the process will be made on the FPSO. So the FPSO will be designed to handle 100,000 barrels of liquids, 65,000 barrels of oil and 85,000 barrels of water, and it will be able to store 1 million barrels of oil before it gets offloaded to shuttle tankers. Now if I go to the FPSO. So the FPSO was acquired by BW Energy. It's ex FPSO Polvo, which was operating for BW Offshore. It's currently in a shipyard in Dalian at COSCO. So we've conducted a FEED basic engineering studies to define all the scope that we need to carry to be suitable for the Maromba oil and the Maromba field. And we have done in-depth inspections so to understand what's required as steel renewal and refurbishment, so it can be operating for 20 years on Maromba. The Polvo FPSO was a turret mode FPSO. We've decided after some studies to transition from that to a spread mode FPSO. We believe that it's a much better solution and its savings as well on the planning, and I will show that in the next slides. So this is a top view of the ex FPSO Polvo, which is going to be FPSO Maromba. And we have color coded the scope. So what is in blue on the illustration is new. So we will replace the offloading all the helideck. We are refurbishing the living quarter. We are installing actually 3 new floor of living quarters, which were found not in condition for new use. As I said, it's going to be spread mode. So we will add the structure to support chain stoppers and all the facilities to spread mode the FPSO. On the process side, we will mostly reuse the existing Polvo process. We will refurbish it, obviously, and we will replace only the heat exchanger at the inlet of the process to be suitable for the new use at Maromba. The boilers were inspected and found not in condition to reuse. So we will purchase new boilers for the Maromba project. So for the wellhead platform itself, so as Carl said, we benefit from availability of heavy-duty jackups. We've secured a jackup for Maromba. So the jackup will be both drilling and supporting the production for the 20 years. We have been through detailed studies on soil and lake penetration at Maromba and also structural studies as we are close to the limit of the jackup capability in terms of water depths. So we've done the static and fatigue analysis, and we've confirmed that the rig that we have selected is suitable for Maromba conditions. One of the challenge, we had to overcome was the conductor pipes. You see in pink on the illustration. So we need to keep those in position for 20 years because we are using dry-trees. So the span between the deck of the jackup and the seafloor is quite high. So to mitigate this and limit the bending moment, we will install a subsea template that you see on the bottom, and this template will be installed by the jackup itself. So that will be fully self-installable in Brazil. There is no specific equipment that will be used for the installation on the supplied vessels. And we have the history of MaBoMo on this. So we have done that before in the group. So we will start by a 6-well drilling campaign that will start when the wellhead platform will be installed and the template is in place. So we will be drilling at depths of 2,900 meters, and we will land in the Maastrichtian reservoir with 800-meter horizontal section. The well will be completed by a gravel pack completions to deal with the sand and to control the sand and with ESPs activation. One key factor for us to go for a dry-tree solution was to be able to maintain our ESP. As you know, the run life of ESP is 3 to 5 years. So we need to have a way of maintaining them. And the solution we selected is really made for that. Our design is also flexible for future upside. So we will be able to connect flexible risers for gas import as we see that along the life of the field, we will be gas deficient. So we will have to import gas from others. We have risk that the aquifer is not connected to all the portion of the reservoir. So we have left space available for future water injection on the process and as well as space available to put water injection risers on the wellhead platform and FPSO. So we will leave space for further upside on the -- on both units. Looking at the planning now. So we are planning to have first oil in 30 months from now. The FPSO is currently at COSCO Dalian shipyard. We have a 24-month program before it leaves the shipyard. The main constraint on these 24 months are the boilers that we are attempting to purchase very shortly and the living quarters that we are refurbishing, and as I said, building 3 floors new. So the wellhead platform has been secured. So we have purchased the jackup. The delivery is scheduled for Q4 '25. We are working on the detailed scope for the yard that we will shortly tender. The idea being to start the refurbishment and conversion as soon as the jackup reach the yard early '26. So this activity will take 8 to 9 months before we can dry to the jackup to Brazil for its installation on Maromba field. And we will start drilling end of Q1 '27, early Q2 '27. The intent being that we have 2 wells completed when the FPSO is ready to start. So we will have first oil with 2 wells already drilled. The SURF is critical because the delivery of flow lines and umbilical is quite long these days. So we have launched a tender already, and we intend to order that by the summer, and it's 22 to 24 months delivery. And finally, the drilling, so we will drill the 6 wells in a row. The drilling is 51 to 53 days per well. And as I said, we will start production after 2 wells, and we will be in CMOS between production and drilling after that. We've mapped out a robust regulatory road map. Sorry, it's very small, but it's really to show you how detailed we went to map all the processes that we will go with the regulatory bodies to get validation on the various aspects of the project. Our strategy is to engage early and be proactive with the different regulatory body in Brazil to make sure that we receive early feedback, and we can incorporate that in our design. Also, we will get the agencies in the yard so that they can audit the unit before it gets to Brazil. We can have the full list of comments and punch list if there is one, so that we can solve that in the shipyard rather than offshore. We know that we will be more efficient in the shipyard to deal with comments than offshore. And finally, our strategy is to repurpose existing unit, and this has a significant impact on our greenhouse gas emission. So we've calculated the impact on both FPSO and the wellhead platform. And as you can see, the FPSO refurbished will generate 75% less CO2 than if it was a new build. And the wellhead platform itself will be 65% lower emission than if we had built a new jacket type platform. So this is a cycling economy. I will hand over the presentation to Thomas, who will talk about the financing.

Thank you. Thank you, Jerome. Hello, everyone. I'll start off with giving a bit of an overview of the CapEx for the project, a bit more granularity. You have the $1.5 billion. That's for the wellhead platform, the FPSO and the 12 wells. And to break that down a bit further, we have $1.2 billion for the initial 6 wells plus the FPSO plus wellhead platform and then $300 million that comes in the secondary phase. The -- prior to first oil, we're looking at roughly $1 billion, and you can see that kind of spread out fairly flat on the phasing of the project. In terms of the $1.2 billion, roughly 70% of the $1.2 billion relates to the production infrastructure, the FPSO and the wellhead platform. That's a relatively stark difference to where we were before with the subsea development. It was rather flipped. It was 30% infrastructure, 70% wells. The benefit we get from that is, we managed to reduce the incremental well cost in a dry-tree development case, which is fairly impactful. So the first benefit we get is obviously we get a higher well inventory because the threshold just went down. A dry-tree well at $45 is roughly 1/3 of the cost of a subsea well. So it means that we can add these next 6 wells, and they're all in the same proven reserves, and they're all highly economical. But it also means we can derisk the project quite a bit. I mean, it's cheaper to deal with issues as they arise. I mean, dealing with ESP workovers is cheaper, faster with an integrated drilling platform. And we can do further appraisal work. It costs roughly $30 million for an appraisal well. That will allow us to further appraise the field and then set up the subsequent phases, which is what we did at Dussafu. It also allows us to test some of the nearby carbonates and the producibility of the field. Carl mentioned it. There is carbonates around the restriction main, and there's also a lot of carbonates over in the west of the field. And that allows us to kind of test and set up hopefully the subsequent phases as we move around. So I'd like to just carry over this $1 billion, that's quite important. Here, you can see the split of the same $1.5 billion, but the pre and post first oil. Obviously, post first oil, it's financed with the funds from -- that we produce at Maromba, which is significant. But prior it has come from external sources. We have initially cash and RBL. So that's cash and available on the RBL. Just as a reminder, the RBL is a revolving credit facility. We can draw down on that, distribute it and spend it on Maromba as we see fit. So we use that to adjust our interest exposure. Secondly, we have the FPSO financing. That's a dedicated project financing for the FPSO. Its Export Credit Agency backed, so ECA backed with China shore. It's with a group of Middle Eastern banks led by ADCB and ABC Bank, and China Exim is in it as well. It's relatively long term. It's 9.5 years door-to-door because the DCA component, it has a lower margin, which is great. And overall, it works well for us because of the -- we can draw as we require it. The wellhead platform lease, we signed a term sheet, someone that we worked with before. It functions as a traditional lease in the sense that we -- it's 100% financed effectively. It's up to $275 million. And it has a tenure of roughly construction plus 10 years, so long tenure, which is helpful. Finally, we have a committed shareholder loan from our largest shareholder, BW Group of $250 million. That's available to us should we need it. It's a 36-month kind of working capital loan that we can put in place rather quickly. So we'll see, do we need to do or not, but that's there for us to use if we need to in relation to Maromba. Finally, you have the free cash flow from the rest of the business. That includes Dussafu, Golfinho, CapEx for Ruche Phase 2, Boost, et cetera. So you can see kind of all in all, we're in a good spot when it comes to funding the Maromba project. I'm going to jump to OpEx. I say it's predictable. It looks very variable. What I mean is -- well, it's variable here because of the OpEx per barrel. What I mean is it's the underlying absolute OpEx is fairly predictable and steady and flat. Only 5%, 10% of the OpEx is variable. And that's -- when I say variable, it's variable with production. And then I mean, it's primarily lifting costs. So you produce more, you lift more, DP shuttle tankers come in more often, you incur a higher cost, when you do that. But generally, it's pretty flat. We've benchmarked this with the fields around Maromba. Polvo, we know very well, the Polvo field, Papa Terra field, Peregrino field. Most importantly, we benchmarked it with Golfinho. That's our operated field. It's within FPSO. It's in Brazil. So we have a decent handle on the OpEx. Key difference with Golfinho, Golfinho is gas efficient. We're importing gas that costs quite a bit. We don't have that issue in Maromba just yet. The infrastructure at Golfinho is older, so more repair, life extension, maintenance costs. But on Maromba, we also have an extra piece of infrastructure, which is the wellhead platform and that will add a little bit of OpEx. So generally, we're in a good spot with OpEx. And hopefully, we'll see some synergies between Maromba and Golfinho as well. The kind of 5-year weighted average OpEx per barrel on Maromba is expected to be roughly $9 per barrel. The fiscal regime is -- it's a simple concession arrangement. So unlike Gabon, in Gabon, we have a PSC, which is more a partnership model with the state. We pay our tax in kind in barrels. Here in Brazil, it's just corporate tax and royalties. This is around 0 license. So it's even simpler. The later licenses have special participation tax, other types of tax, we avoid that. We also do not have any local content requirements on Maromba because it's around 0 license. So we added a comparison here. It's from Rystad, shows comparisons of government takes. Obviously, lower is better. And actually, because Maromba is around 0 license, we sit a little bit below that. So we're somewhere between 35% and 40% government take, which is good. We included this graph here, Maromba is positioned among top global projects. This is from Goldman Sachs top 100 projects. It shows top as in having a low breakeven. Maromba isn't currently on the list, but maybe one day. The difference is really with these mega projects is typically you achieve scale by having a big investment, bigger investment, you bring down scale, you bring down that cost per barrel. Really for Maromba, which currently sits in the top 10% of this list in comparative basis, we achieved that similar scale on the economics by redeploying infrastructure. So really by bringing down the cost of the infrastructure, we've actually able to bring down the breakeven to $40 a barrel, which is quite significant. And you could say, yes, a greenfield is risky, but a greenfield can also be -- with economics like this can also be quite forgiving in the sense that -- I mean, if you just take the GranMorgu project in Suriname, that's a $10.5 billion project with a $57 breakeven. For us to achieve that and to still be below the average breakeven of the top 100 projects, we could have a more than 50% overrun on the Maromba project. So it speaks a little bit about the -- how robust the economics are in Maromba. Finally, we're set to generate material value. We set a target in 2020 of achieving 50,000 barrels of operated production. With Maromba, we'll get close to 100,000, especially together with all the other stuff we got going on. We will reduce our OpEx in half, which is big. Our OpEx per barrel will go from roughly $30 to roughly $15 per barrel, which will make a big difference. And it will give us diversity and they will give us diversification and will also give us materiality, which is key. And I think most importantly, it will also continue to prove up this model where we take, we buy undeveloped barrels, we unlock them through repurposing existing infrastructure, which allows us to get great economics like this. And there's not a lot of other companies like us that do greenfield developments like this. So yes, I'll leave it at that and hand over to Brice.

Thank you, Thomas. So as you have noticed, this is our best quarter since start-up. So all of this is possible because our financial situation is very strong. We have a strong balance sheet and a very good result coming from the operation. We had 3 Dussafu liftings and one Golfinho lifting in this quarter, supporting the -- so the operating revenue is very solid due to a strong production. We had again a loss in oil derivative of $0.9 million, that's unrealized and operating expenses of $99.8 million for this quarter. Depreciation and amortization is a bit up. This is due to the higher production. And we have some adjustment in interest expenses and other financial items. So a profit before tax of $109 million, $26 million of income tax expense. There is $8 million of tax deferment adjustment in it. And so we finally have $83 million of net profit at the end of the quarter. So very good result for the company, supported by strong production. To the cash flow, we had $221 million at the end of December, operating cash flow of $155 million and net investment activities of $81 million. $8.6 million of net financing activities and a cash position at the end of March of $286 million. So we have a total available liquidity of $407 million. That includes the undrawn debt, $120 million on the reserve-based lending facility available at the end of the quarter. To the balance sheet, we have a very strong balance sheet supporting the execution of our growth strategy, $2.1 billion of total assets. There is plus $50 million in Dussafu this quarter, net interest-bearing debt of $296 million. Very strong equity ratio of 46% and NIBD/EBITDA of 0.56x. You can see on the right side of our presentation, the maturity profile of our debt. So in here, we have $100 million of bond, the $80 million of the Golfinho prepayment that we intend to repay by the end of '25. The Dussafu RBL, $280 million, the maturity will be 1st of April 2028. We just renewed the facility and increased it to $400 million with an accordion option of $100 million, and the MaBoMo lease of $138 million. So very strong balance sheet. And I think it's the right moment. It's the good momentum for us to sanction our 2 main projects, Maromba and Golfinho Boost because we have a solid balance sheet and operational cash flow to support these developments. For the guidance, we give the same guidance for production, operating cost and G&A. On the operating cost, the OpEx are lower on our 2 assets, Golfinho and Dussafu. We had $11.7 per barrel OpEx in Gabon. That has been decreased to $9.9 this quarter. This is mainly due to more reliability in the process and less diesel consumption. And we have exactly the same figure in Brazil, 45% -- $45 per barrel OpEx down to $42, also due to less diesel consumption and as well better tax on the diesel purchase. And we have a higher guidance for the CapEx. So this includes Maromba and Golfinho Boost, $650 million to $700 million net for the company in 2025. This is the last slide of our presentation. BW Energy is a fast-growing E&P company with a differentiated strategy. The production is growing. Production is going up on our 2 assets, Golfinho and Dussafu. Costs are going down, thanks to the operational efficiency, operational excellence of our team on site. We have a diversified asset base, so material reserve on both sides of the Atlantic in Gabon and in Dussafu, a success with Bourdon that we intend to develop as well and exciting wells in Kudu and as well good opportunity with Niosi and Guduma in Gabon. So basically, we have a material reserve for the coming decades. And what we intend to do, BW Energy intends to do exactly the same thing as we've done in Gabon is to develop low-risk reserve with repurposed assets. We've done that in Gabon, and we will do that on the other side of the Atlantic in Brazil. And we already have an established subsidiaries, very competent team. So we know how to operate in Brazil, and that's the right time to do it for us, and we are in a good path to double the production by 2028. And everything -- all of this is possible because we have a solid capital structure, solid balance sheet and a well-diversified source of financing. And I think that demonstrates our disciplined approach to investment. Thank you very much for attending our presentation, and now we will take questions in the audience and then from the web. Thank you.

Yes, Teodor?

[indiscernible] farm down before first oil. Could you talk about if you had any incoming costs at all? And then final question on the Golfinho Boost project, will that impact the production cost per barrel? And if so, how much?

So we expect to start with 2 wells on Maromba, and then we expect the drilling time to be around 60 days per well. So that will be the ramp-up. So we'll complete the -- let's say, the remaining 4 wells in the first set of 6 in 4x 60 days, so 240 days. So a bit under a year. So that will be the ramp-up. The second...

And just for modeling purpose, then we should assume 60,000 barrels per day by end of '28 maybe.

Yes. Early -- well, yes, it will be -- so we will start up, let's say, sometime between third quarter and fourth quarter in that 3-month period. And then you could add 240 days. That's your ramp-up.

And then on farm down?

Farm-down, we -- I mean, everything is for sale. So if somebody comes to us and wants to buy into Maromba, we'll certainly entertain discussion. But as you understand we're extremely comfortable about our project, and we're prepared to run it 100% on our own tab. So we're very comfortable with Maromba. We're very confident with our plan. Yes, sure, if somebody wants to buy in to this exciting story, we'll talk to them. But they will need to pay us a handsome pots of gold to get in. It's that simple. No, I mean, I know we're a bit unconventional, but when we get our head around the project and the development, we are prepared to go along. And we have done that more or less. I mean, we lifted all of Dussafu in reality. I mean, we borrowed money to Panoro to do their part. So we're comfortable.

And then Golfinho OpEx boost.

Golfinho, that's a slightly different project. First of all, getting into Golfinho was really, we saw it as a very interesting way into Brazil and get established in Brazil. But the main thing about getting established in Brazil was for Maromba to have a working relationship with the regulatory agencies in Brazil and have a working organization because Brazil is tricky. And if you just land there day 1 with a $1.5 billion project and think everything is going to be hunky-dory, then I think you're doing something dangerous. So we really wanted -- we were looking for something like Golfinho and we found it. Golfinho has in itself quite an interesting set of upsides. What has happened is that the subsea market has become quite frothy, and we've had high cost inflation. So we've been back on our ambition on doing infield wells. But there's a great potential for it, but we don't think it's the right timing for that due to the frothiness of the market. So we're -- if the market comes down a bit, we'll be there. But now the project is really the fine-tuning of the machine. So we're fine-tuning the production asset. We're fine-tuning the well performance, and we're installing some -- these subsea skids that we have developed to boost production from the existing infrastructure. That's Golfinho Boost. So it's 3,000 barrels increment. I think kind of end -- we expect end '27 to be up to that. Of course, we'll have some decline in the meantime. So you have to kind of do a little bit of curve shifting. So that's where we are. I don't know if you guys want to add anything?

Just that, we are also studying the reopening of certain wells of [indiscernible]. So those may add additional production. We are increasing the water handling capacity in the FPSO to do that.

There was some more questions.

Tom Erik from Pareto. A couple of questions, please. First, congratulations on Maromba, getting the FID, I think, stronger economics than some expected as well. Looking forward now, where do you see the biggest kind of risks and which milestones should we look the most for? Is it execution on yards? Is it production from the wells when you start those up? Or is it kind of the regulatory process that could kind of trigger some delays? Or what are you most worried about to put it that way?

Well, I mean, obviously, all the risks we know we're trying offensively to tackle ahead of them being becoming a problem. So we have already gone to the yard. We have already done the demolition. We have a unit that we know well. So we have tried to derisk the yard, and we have 24 months of yard stay in our plan. That is -- I'm almost crying. It's too long. We should make it -- should be able to make it faster. So I think we have a very -- I don't want to say relaxed, but I think we have a very, very hyper realistic schedule. I don't think we'll miss that one. The regulatory process, again, we have a working relationship. We're in constant dialogue. Again, we have tried everything we can to derisk it as much as we can. The work scope for the rig is very limited. It's a bolt-on kit. Most of the stuff is going on, on the FPSO. All will be serviced from the FPSO. It's more or less just dumb steel parts going on. The rig in itself is capable of drilling. We, of course, need to inspect it, change anodes, et cetera, but the work scope is fairly limited. And it will remain more or less as is with a little bit of additions. The kit we will build to add is really going to be installed by the rig itself. So we'll bolt on the well bay and we will install the frame that we showed on one of these captions. So again, we have a very, I think, realistic schedule, not aggressive at all. It's not a kind of hurry up type of schedule. So again, we're super comfortable. I would say the only thing is the things I don't know. So obviously, I cannot speak about them because I don't know them. Those are the risks that are -- that -- okay, it's very difficult to quantify what you don't know. But everything we know, we're comfortable.

Perfect. Can you follow up a bit on that work with yards? How much of a difference does it make that you're part of the BW Group and have that main shareholder when you contact them and have them engaged to work for you? Is that a huge difference or?

Well, it depends where you are. Of course, in China, it makes a big difference because in China, we have -- the group is building a lot in China. COSCO has just built quite a few wind turbine installation vessels, among others, for the -- for a group-related company. So yes, we have very good relationships there. Less so in other places because, well, they're less frequented by group vessels. But in general, I think we have a reasonable name, yes, with the association or affiliation with BW, if you like.

Okay. And on Dussafu and on the discovery there now, are we starting to see kind of maybe too early to put it into reserves and you need some planning. But internally, are you starting to see that you can maintain plateau to 2030 and beyond?

Yes. I think we're full steam ahead already on the Hibiscus/Ruche Phase 2 drilling campaign. So that's being addressed and that was being addressed when we made the discovery on Bourdon. So now we're kind of, of course, stepping through all the potential bumps that we see around Bourdon because there's more there. You have -- if you remember, we had -- in the old days, it was called Prospect A and Prospect B. So Abelia is the new A. Abelia is still there. So yes, we have -- so we're now kind of stepping through all that based on the drilling we have just done and the new data we have from that drilling. So -- but we will probably be more forward leaning and go full speed on a development because we know we have sufficient resource for development anyway. And we may also then, of course, end up with 2 rigs in the yard, which could give some benefits as well.

Okay. And last question for me. If you take big picture, now that you added a major development, a lot of growth, does that -- should we think that now the company will be solely focused on delivering this? Or could there be that you also want to balance with more acquisitions like you've done in the past of producing assets, things like that? Or will you not kind of have capacity to look at that as well?

Yes. We're quite happy to invest counter cyclically. So investing -- I mean, the oil price isn't great. But we are quite happy to invest in this environment. We know we have the projects that can support even this oil price. So we're okay. Are we then interested in doubling up with taking even more oil price risk by making brownfield acquisitions? That's something we're mulling over. There's quite a few opportunities out there that we are looking at. But a brownfield is more of a -- it's very much a pure oil price play risk. And how much oil price risk do you want is something we have to ask ourselves.

[ Petter ] from Pareto. A bit on financing. Can you provide some color on the margins on the asset financing on Maromba?

We typically don't disclose that, but it's on Maromba because of the ECA backing on the FPSO financing, it's rather low, lower end of the scale. For the wellhead platform lease, it's kind of mid -- let's call it midrange for the margins. But because of the tax benefits you also get in terms of a lease, you do get some effective tax rate deductions on it.

And it's good to see the committed shareholder loan from BW Group, and you're writing in your comments here that you are considering as alternative financing solutions. You're well financed as seen from the project financing. Will that be in addition to the shareholder loan, you think or instead of it, how do you look at those kind of things?

Well, it's -- again, it's partly an oil price question because we do -- depends -- the oil price will give a little bit of -- or will play over into how much free cash flow we get. And we typically like to be a little bit of belt and braces on the liquidity side. So the shareholder loan is very useful. It gives us great optionality to look at, okay, other types of financing. We have been looking, as you know, in the -- on a Nordic high-yield bond, we did one last year. We like the instruments. We are quite -- we would be -- when the time is right, when the conditions are right, we would be absolutely looking at that. But we're also looking at other types of corporate finance as well. Some, let's say, not Western banks, but other banks are still quite keen on the E&P space. So we're trying to open up new, let's say, tools there, too. Yes.

Any other questions from the audience? No?

Then we maybe take some questions from the web.

Yes. So questions from the web. Do we have? What water depth is the Kudu field and the Kharas wells? I think it's 640 meters. That's what we target for this well. Will the Bourdon new development include subsea wells or a new jackup with dry-tree? So this will be a dry-tree development. We intend to do quite the same thing as we've done on MaBoMo. So no subsea wells. Question on regulatory. How do you -- how are you prepared to get all the approvals? Maybe a question that you can take, Alex. Alex is our regulatory specialist in Brazil.

Yes. As has been said, we already operate in Brazil. So we know how to do that, and we plan ahead. We have already started the main processes. We have reviewed recent projects. We have set a very strong plan, and we have approached regulators, show our plan, get their comments. We are very aligned with them. So we are very confident that we are going to deliver the schedule.

Thank you, Alex. Other questions on Maromba reservoir. Can you elaborate on the reservoir that you have and the work previously done by Petrobras? We have our Subsurface manager, Chris Boyers, maybe you can take that question.

Yes. What's interesting about Maromba is since all the activity previously was done by Petrobras, it's really -- the question to ask is what haven't they done? They have pretty deep pockets. Most of what they've -- most of what you see they do when they execute exploration or appraisal, they acquire all the data that you would. In fact, most operators would require less, would spend a little less. So we feel that Maromba is quite well delineated. And numerous well tests, not just the 2 in the Maastrichtian, which is the primary reservoir, but also in other reservoirs that we want to appraise later and develop on. You name the log, you name the sample, you name the study, it's pretty much fully covered. So I would say, if we would have done it out of the gate or Chevron would have done it out of the gate, we would have acquired less. So I think for us, we feel very confident that we have about as much as we can use.

Thank you, Chris. Other question from the web. I think for you, Jerome, will the Maromba FPSO flare off all produced gas? Or is it only liquid produced?

So obviously, we will start with a small production with 2 wells. And we will ramp up, as Carl mentioned, over a period of 240 days. So the production initially will cover the full gas requirement for the field. So at some stage, we will have an excess of gas, and it's going to be for a temporary period of estimated 12 to 18 months where we will flare the excess. But most of the gas will be still used for power generation. After this, we will get to further drilling to maintain a plateau of gas production to keep up on self-power generation. And we know that the GOR of the field is not sufficient to support the production of electricity for the 20 years. So we will be gas deficient in a certain time. So we will flare partially for a short period at the beginning of the production.

Thank you, Jerome. We answered most of the questions on the web. Maybe the last question. What are the major FPSO upgrades and key long lead items? What are the key risk factors associated to this development plan? Maybe we can ask our FPSO manager, Kei Ikeda.

I think the -- as mentioned by Jerome, the long lead item is a boiler that is 18 months, okay? But we have done all sort of preparation to shorten the integration and the commissioning stage. So that's one. The rest of the equipments are quite simple. There's no major rotating machinery like our power gen, gas turbine, we don't have and water injection, we don't have and gas compression, we don't have. So we are quite confident with the long lead item. In terms of the major risk of the redeployment, looking around the industry, usually, the supplies of the condition is usually the case. We have a very unique advantage of having the people who has actually operated both on onshore and offshore in this Polvo project. And they are -- they were involved during the FEED for the condition assessment. So in terms of this risk, we are quite comfortable.

Thank you, Kei Ikeda. Well, thank you. I think we answered all the questions. Thank you very much for attending BW Energy presentation. And Carl, I leave it to you to close.

Well, I don't think I have much to add to that other than, again, thank you for attending. And I hope we've given you a flavor of the Maromba FID, and why we are so excited about this project and the next step in the development of BW Energy as an E&P company. So thank you for attending, and, looking forward to talk to you again, hopefully, not very long in the future. We discussed a bit before everybody arrived whether this format is good. I know we have become a bit lazy and it's so convenient to sit behind your desk and do a webcast. But maybe we should at least on a regular interval do this face-to-face again. So thank you for attending.

Thank you very much.

Thank you.