Good morning, everyone. Pleasure seeing you here live at Hotel Continental in Oslo, and also welcome to you who are following us on stream.

My name is Martin Simensen, I'm head of Investor Relations in BW Energy, and I'll take you through the Q&A session later. First, we have a large part of our management team here today travelling in from Lisbon, they'll take you through the Q1 2026 and strategy updates.

Please save up some questions for them after the presentation. With that, I'll leave the word to our CEO, Carl Arnet.

Thank you, Martin. Again, warm welcome to this presentation of first quarter and we have added a small update on our activities.

Please note our disclaimer, as usual. Today will be hosted by first, our Chief Operating Officer, Brice Morlot, that will take you through the operational update.

Then Jérôme Bertheau will take you through the Maromba update, and then Thomas Young will round it off with the financial update. I will have the pleasure of taking you through a little lead-in where I boast about our exploits, of course.

Then Martin will be the moderator for the questions, Q&A. First quarter, all projects on plan and cost.

We have been able to sanction Bourdon and new Golfinho wells, and we have lifted our production target to more than 100,000 barrels per day sustained production into the next decade. We have a strong position financially, and we are generating cash, the business looks good, and we had a very decent operational performance in the first quarter.

That's the bottom line. EBITDA $111 million, net profit $33 million, and this will, of course, be gone through in detail.

Our end cash position was a healthy $161 million, plus we have, of course, unused facilities on top of that. BW Energy is delivering on its growth strategy.

We are pleased that we can now say that Maromba, which we presented to you last year, more or less exactly a year ago, we said we were going to do funding, we have delivered on all the funding activities, we have acquired the jackup, it's now in the yard and the commissioning has started, and the FPSO upgrades are going well. We are very much on track for first oil in end 2027, and we are working hard now on the next phases of the Maromba development.

This is, of course, a big transformative project for us, and we will go through that in more detail. Golfinho Boost project is on track.

We have done the initial subsea work, that is completed. We are now entering a phase where we will focus on the FPSO and optimize that and its operations.

This is an old asset, and we have to lift the performance of this asset, which is something we have known about for a long time, which we are very capable of, we have done this many times in our previous life so we know exactly what to do. It is a significant effort, but we have now a very clear path for production and production increase, and that's why we are now going to take this significant step and upgrade Vitoria.

We have sanctioned Bourdon. This will add very material resources to our Dussafu license.

We have also achieved a license extension, but more of that will follow. The Bourdon development will follow the MaBoMo blueprint, it's a sister rig, it will be a somewhat simpler topside, but it will have 12 well slots.

This is, of course, to be able to harvest from the Greater Bourdon area. It will be placed in a location where it will have very nice reach or nearby potential resources.

We have also sanctioned four Greater Bourdon area appraisal wells, and we will also drill one well in the Walt Whitman area as the next area in the Dussafu license we want to unlock. Again, Dussafu continues to deliver.

We're extremely proud of the license and what we have been able to do with this license. Golfinho, we have sanctioned new wells.

These are infill wells, low risk wells that we will drill and connect to the infrastructure that is there. We're targeting to lift production from Golfinho to 30,000 barrels, and we have now completed a very extensive study of the total Golfinho area.

We have a huge license in Golfinho, and we've had the time to go through all the data that we have acquired with the license from Petrobras, the previous operator, and we are finding a lot of opportunities. More wells and more appraisals will follow on Golfinho as well, and we have identified a huge number of targets for these activities.

We are actually 10 years this year, BW Energy, and if we look back from 2016 when we started, we estimate that about $300 million has been invested, and the current market cap is $1.5 billion. We are, I think, rightly proud of that, and as we are going to explain today, there's a lot more coming, and we're targeting more than 100,000 barrels per day in 2028.

Our model, we have explained this many times, but I think it doesn't hurt to repeat. We are looking at discovered resource, but that cannot be unlocked, with potential.

That's the first step. If we get access to it, we reuse existing infrastructure, we repurpose facilities.

We thereby do not have to take on the huge investments associated normally with oil and gas developments, we limit the cash at risk. We are now fully capable of doing all developments internally.

Of course, we use subcontractors, but we run all our projects in-house. Then we prove up, we show that our models are working, that we get the production we're supposed to have, and then we scale.

On top of that, we have very efficient infrastructure financing, we are very capital efficient. This is the BWE model.

I think we're quite unique in many of these aspects, and in particular, I think we're unique in our ability to repurpose existing assets and in the financing that we have managed to put together for these assets. If you look at our assets, we have demonstrated this strategy, I think, very clearly.

Dussafu started out 24 million barrels. Today, we have increased that by 580%.

Golfinho, not as significant yet, but we're working on it. Of course, Maromba, there was no clear path to development at all, in percentage terms, it's unlimited, but, of course, it's 122 million barrels of reserves in the current development.

In aggregate, I think we have an excellent track record of expanding our high-quality resource base, and we have had excellent reserve replacement, which I think is also a bit unique, as this is getting tougher and tougher in the industry in general. Our portfolio, today production is about 25,000 barrels per day.

We operate two production assets, Golfinho and Dussafu, and as you can see, we have five projects in execution, and our total reserve base is more than 600. We have a lot of reserve life left at current production, but we're also, of course, working to increase our resource base.

We operate in what we consider to be very stable locations, very stable countries. I know there are some confusion on what stability is.

We're not necessarily talking about political stability, but we're talking about stable conditions for the type of business we are in. If you look at Gabon, they have an excellent track record of 100 years of never challenging PSA terms.

That is more than you can say about a lot of other places where oil and gas operate. Brazil, we also see that as a stable country in terms of their support for the oil and gas industry and their interest in exploiting their indigenous resources.

A bit more temperamental on tax, maybe, but still, we regard this as a very stable place. Other places like Namibia, we think also has great stability.

We operate in what we consider to be an interesting part of the world, the Atlantic Margin. Today we have three projects in execution that will add 154 million barrels of oil equivalent 2P reserves.

We have just FID'd two more projects which will add 68, and we have significant growth potential in all these licenses. That is really the bottom line.

We have a clear path to sustaining more than 100,000 barrels per day production, and as you can see, this is how it's composed of project producing, project in execution, and appraisal and upsides. Of course, we have a significant exploration activity, and just to remind everybody, we recently shot seismic of the Niosi and Guduma licenses in Gabon.

We also covered the Walt Whitman part of the Dussafu license where the seismic resolution was not perfect. We are active also in the near-field exploration activities already.

Investment case: more than 600 million barrels of oil equivalent reserves and resources, more than 100,000 barrels per day by end of 2028, more than 30% IRR at $60, and we will generate between $2 billion and $4 billion at $60 to $90 oil price until 2030. With that, I will hand over to Brice that will take you through Dussafu and Golfinho and the operations in general, and then he will hand over to Jérôme that will go through Maromba, and then we have Thomas that will take you through the financials.

Thank you, Carl. Good morning, everyone.

Operational performance and production availability stays high. At Dussafu, we completed a well workover to maintain ESP.

The job was completed with a hydraulic workover unit, without a rig, in 3 months, we are very happy with this result. Dussafu has since returned to normal operating level.

Production availability for the quarter is high, at 86%. At Golfinho, the production was impacted by one unplanned well maintenance, but corrective measures are underway, and the availability for the quarter was 79%.

On the rig schedule, we have decided to optimize the 2026 drilling sequence to confirm the potential of the Northwest Hibiscus area. We will drill two pilot wells, the 10P-1 and 10P-2, and the objective is to confirm this area up front, because in a case of success, we will install two additional slots on the MaBoMo well bay, and we will increase the well capacity of the platform from 12 to 14.

That means that at the end of MaBoMo Phase 2 drilling campaign, we can add two additional wells, and we'll have six wells in production by end of 2027. Therefore, we are updating the 2026 guidance to 23 to 26,000 barrels per day.

The revised drilling sequence is a value-driven decision, and it sets the stage for higher long-term production capacity at Dussafu. On opex, opex were impacted by one workover in Gabon and one unplanned maintenance in Brazil.

The Q1 2026 opex came in at $26.9 per barrel. This reflects two factors: the lower production because of the Golfinho well maintenance, and the workover cost at Dussafu.

In light of this production outlook guidance revised, we revised as well the opex guidance to $22 to $26 per barrel. The change is driven by a revised production range, and it's not indicative of a structural cost increase.

Let's go to Gabon now. Dussafu remains the backbone of the company, and this illustration is interesting because it demonstrates the strategy of the company, which is repurposing assets to develop discovered resources.

The company installed the FPSO Adolo with just two subsea wells, and at the time, the recoverable reserves were only 24 million, which is very low. Since then, the reserve have been multiplied by seven.

Tortue was a success. The company added four additional subsea wells, then spend money in appraisal, discovered the Hibiscus field.

They installed a jackup, repurposed a drilling rig as a production facility, with more slot, with 12 slots, and it was a success because today we have eight ESP in production, and at the end of MaBoMo Phase 2, we'll have 12, and maybe 14 if Northwest is a success. That's great.

In Q1 2026, the asset produced 19.2 thousand barrels oil per day for the quarter, net to BW Energy. Operating costs in Gabon are low, at $16 per barrel.

One important milestone is this quarter, we have now produced a total of 50 million barrels on the Dussafu license, 50 million barrels produced already in this license from zero. We are continuously adding new discoveries with minimal incremental capital, and we have grown the net 2P and 2C recoverable resources to 136 million barrels.

Since 2017, BW has delivered good reserve growth and multiplied by seven. We can now zoom in on the reserves.

This slide is quite interesting. This slide captures the reserve and resources trajectory of Dussafu and the underlying approach that has driven it.

11 of 12 successful exploration and appraisal wells since the inception, and at the beginning, in 2017, the reserve have grown from 24 million to 163 now. This track record speaks directly to the quality of our subsurface understanding.

Looking ahead, there are a lot of left potential in the license. All the yellow dots you see will be appraised, and we have both short-term and long-term plans for the area.

Let me go through the next drilling campaign. This is the MaBoMo Phase 2 drilling campaign.

The drilling program is designed to maximize long-term value rather than near-term production. We will spud in July with the Borr rig, and we will first drill the Northwest region of Hibiscus to appraise this region, and in case of success, that would trigger two additional development wells.

We have the long-lead items, in case of success, we will put those wells in production. MaBoMo Phase 2, outside of these two additional wells, is four wells that will be put in production end of 2026 and in 2027, and each well will add 5,000 barrels per day, with a first oil expected by the end of this year.

Then we will present you Bourdon. Bourdon is the next step on Dussafu.

This is a major development for us, and we are very happy today to announce that we have made final investment decision on the Bourdon project. We have a short video to show you the project.

BW Energy started the development of Dussafu with a simple and fast-track approach targeting the Tortue field. The field was brought to production in just 18 months, making it one of the fastest offshore greenfield developments ever delivered.

BW Energy's strategy is to unlock discovered resources through phased developments and reuse of infrastructure. Instead of committing large capital to full-field developments, we start with a minimum case, an approach that limits capital at risk and brings fields on stream quickly.

Then, as production data confirms reservoir performance, we grow into the opportunity step by step, unlocking additional reserves and value over time.

BW Energy has continued to successfully develop the area with the addition of the MaBoMo production unit in 2023, bringing the total production up to 40,000 barrels per day early 2025. In parallel with these key milestones, the exploration team drilled the Bourdon prospect nearby and discovered the presence of 25 million barrels of recoverable resources.

The Bourdon discovery from 2025 is the next step in our phased development strategy. It will establish a new hub that will fast-track production through existing infrastructure and a new wellhead platform.

The project economics are strong with a breakeven oil price around $45 per barrel and an average annual return above 25%. At Dussafu, our phased development strategy has already increased reserves more than seven times the original estimates.

We hope to create a similar story around Bourdon, which has several interesting upsides already identified.

To date, BW Energy has discovered or successfully drilled 11 out of the last 12 prospects here, a remarkable track record for any operator. The development of the Dussafu area, together with the new Bourdon expansion, fortifies BW Energy's position as a key offshore oil producer in Gabon, accounting for 15% of total production in the country.

The company continues to successfully expand the Dussafu reserve base, which, along with several other prospects yet to be drilled, will support the company's long-term production and value creation in Gabon.

Thank you. We love Gabon, we'll continue to invest in Gabon.

This license keeps on giving, and there is more to come. The next phase is Bourdon.

Bourdon is unlocking growth. Phase 1 targets 25 million barrels of gross 2P reserves.

First oil is planned in Q1 2028. The project delivers strong economics: IRR of 25% at $60 per barrel.

We have a capital-efficient development concept that replicates the approach we have proven at MaBoMo, with a redeployed jackup. Basically, it's a blueprint of MaBoMo, but with an optimized development.

After that, we will have another phase. We call this the Greater Bourdon area.

This area contains additional unrisked oil-in-place, with Bourdon Updip, Bourdon Southwest, Southeast, and Abaye. By installing a 12-slot wellhead platform here will enable us to produce this region as well.

All these targets are reachable from the platform that we will install. The development of Bourdon is a capital-efficient design, with the capacity to scale.

You can see on the right how we intend to develop this field. We will have a jackup rig that will be converted as a wellhead platform, 12-slot well bay, given us ample capacity to future appraisal wells.

The new wellhead platform will be uninhabited. We want to leverage the MaBoMo living quarter, and we will transport the crew with boats between the two platforms to reduce the opex and leverage the existing assets.

There will be three initial ESP wells, and the production will be exported in multiphase flow, oil, water, and gas, through the existing pipeline. The power will be supplied by Adolo, the FPSO Adolo, to leverage the existing power capacity.

MaBoMo wellhead platform will be as well connected to a subsea cable to reduce the diesel consumption on MaBoMo. We will have an integrated electrified field from the FPSO Adolo.

This design reuse existing infrastructure to the maximum extent possible, keeping capital requirements low and execution risk manageable. Basically, Bourdon is a blueprint of MaBoMo, but with an optimized approach.

On the capital side, Bourdon economics are compelling, and we have an efficient leasing structure. The total Phase 1 capex is approximately $300 million, covering the wellhead platform and four wells.

There will be three producer and one pilot to appraise the Bourdon Northwest area as well. We will order the long-lead items, and we will put this well in production in case of a success.

On the leasing side, the long-term lease cover 100% of the wellhead platform cost at a highly competitive terms. The term sheet is now signed, and so the lease structure will cover $200 million, and $100 million will be for the drilling part.

Economics are compelling: the IRR is above 25% at $60, breakeven of $45 per barrel at 10% discount, and a payback of less than two years. This project is providing strong returns, minimal upfront capital, and very important, there is no balance sheet conflict with the Maromba development.

This is for Bourdon Phase 1, but we have other phases. Beyond Phase 1 of Bourdon, I will show you how Dussafu looks like.

We are working on a five years business plan. The Dussafu area has a clear multi-year drilling pipeline, targeting 30 to 45,000 barrels per day.

Bourdon Phase 2, the drilling will start in 2028, and we are targeting 200 million barrels in place across Abaye, Bourdon, Bourdon Southwest, Bourdon Southeast. Then we have the Walt Whitman area, and we want to create another satellite here.

There is an existing discovery. We are actually working right now on the reprocessing of this region, and there is as well 200 million of potential oil-in-place in this region.

All in all, the total appraisal spend from '28 to 2030 is approximately $100 million. This is the future of Dussafu.

Each platform we install will unlock a new wave of development, and that's what we going to do as well with Walt Whitman. That was to cover Gabon.

Now we will go in Brazil, and I'm going to cover Golfinho. Golfinho is 100% operated and owned by BW Energy.

The production this quarter was around 6,000 barrels in Q1, and we are very happy as well to announce that we have made FID on three infill wells long-lead items and the tieback of the Camarupim field that you can see on the right. There is an existing wellhead on this field that we acquired, and we will just put this wellhead back in production to the FPSO Adolo by pulling a new pipeline.

This new phase targets approximately 15 million barrels of reserves, with highly attractive economics. Beyond that, we have as well a phased program to unlock Golfinho, with more than 500 million barrels of near-field appraisal targets, including Camarupim and the field on the right that is called Brigadeiro.

On the reserve side, the company acquired Golfinho in 2023. The 2P reserves have grown significantly, from 40 to 105 million barrels.

The new phase will extend the field lifetime, but as well adding reserves. This is the 64 million you see on 2C resources.

We see the license as highly prospective, with multiple gross opportunities, and the existing infrastructure of the FPSO and as well the pipeline that the company owns can allow us to export gas and sell gas onshore. It provides a very attractive tieback opportunities.

I will give you an update on the Boost project that we sanctioned last year. Golfinho Boost project is progressing to plan.

This project is on time, on budget. The purpose of this project is to change the artificial lift system from gas lift to seabed ESPs.

It's a 12 million barrels of incremental reserves. The purpose of this project is to set the stage for the infill wells, stabilize the production to 10,000, and stabilize the uptime as well, because we are investing in maintaining the FPSO.

It will add 3,000 barrels of production plateau, and the capex is around $107 million, so far on budget. Good economics as well: $47 per barrel at 10% discount.

The real step change for Golfinho are the infill wells program that I'm going to present to you now. The Golfinho infill campaign triple the production, roughly from the 10,000 after boost to 30,000 when the three wells will be online.

The project includes two gas wells, the tieback of Camarupim and a twin well, Golfinho 50, and two oil wells, two twin wells, Golfinho 51 and Golfinho 54. Production will start end of '28, and the main capex will be spend after Maromba first oil.

The campaign targets 50 million barrels recoverable. Actually, those wells are some of the highest returning project in our portfolio.

In terms of capex, in total, we will spend $450 million, of which only $170 million are committed to the long-lead items, with investments starting in H2 '26. We want to order the long-lead items to reduce the rig commitment time.

The remaining $280 million are optional, and it will depend of the condition of the market. The development costs are quite low, it's $9 per barrel, and this is because of the existing infrastructure.

In terms of economics, the economics are excellent: breakeven for the $40 per barrel at 10% discount, IRR above 50% at $60 Brent, and a payback of around 2 years. In sum, the launch of the first well campaign on Golfinho makes a lot of sense for us now, and it shorten our decision cycle on rig contracting, and it allow us to act swiftly on attractive opportunity in a downcycle market.

This is the last slide of Golfinho, and it's to give you the flavor of what we call Greater Golfinho area. There are a lot of opportunities in this block.

We are currently working on optimizing Golfinho production through Boost. Then there will be Phase 1 with the four wells, tieback of Camarupim and three infill wells in the reservoir we well know.

Then there will be Phase 2. Phase 2, there will be a second well in Camarupim, Camarupim-5H, which look commercially very accretive.

The broader area on Phase 2 contains a mix of undeveloped discoveries with DSTs and exploration targets as well. We are actually working on reprocessing the seismic of this Phase 2 region.

Then there will be a Phase 3. A study is ongoing to evaluate the possible tieback of Brigadeiro.

There are as well discoveries on this block and DSTs. Then Phase 4 is more exploration driven phase, with additional targets within tieback distance to the FPSO.

This is Golfinho. This gives you an indicative plan of what we intend to do in the coming 5 to 7 years on Golfinho, but we are very excited with Golfinho, we see a lot of potential on the Greater Golfinho area, and we are looking forward to progressing the infill development program.

Then, I will give the floor to my colleague Jérôme that will present you the Maromba project.

Thank you, Brice, and good morning, everyone. We were here a year ago to FID this Maromba project, and we are now in full execution phase.

As a reminder, Maromba entail a production platform, a wellhead platform, which is a converted jackup that you see on the illustration here, which is being converted in Dubai, and an FPSO, which is a repurposed Polvo, and being converted in Cosco Dalian in China. The key figures of the project remains the same.

We are targeting 60,000 barrels of oil per day from end of 2027, with a plateau. This is developing 122 million barrels reserve, at a below $10 per barrel opex, and a breakeven around $40 per barrel.

This is in the best ranking of the worldwide project today. We have a very good project here, and I'm pleased to report that we are executing on time and on budget.

This is per our target from last year. Going now in the different workstreams.

The FPSO is in Cosco Dalian, as I said. We just completed the first dry dock.

All long-lead item are on order and all the vendors are confirming that they are on time. Topside refurbishment is ongoing, preparing for the new module to arrive, and we are targeting sailaway to Brazil in March '27.

Wellhead platform has arrived in Dubai end of last year. We've spent three months to do in-depth condition assessment to understand the full scope.

We dismantled a lot of mechanical equipments to go for OEM refurbishment, and we are now working on the leg extension. We've completed two out of the three legs, we rotated the rig two weeks ago to be able to do the last leg extension.

Then the next step will be to go to dry dock and then restart the unit before it leaves to Brazil. The last workstream is preparation for drilling.

We've purchased all the tangibles, they will be delivered by end of the year. We are tendering all drilling services and the O&M services.

We are planning to get the rig to be operated by a third party in Brazil. We will work on the mobilization of the crew in Dubai to commission the unit before it leaves to Brazil.

The idea is to have a fully commissioned unit before we leave Dubai. Going now into details of the FPSO.

We've been in dry docks during Q1. Dry dock lasted 55 days.

We've replaced 1,500 tons of steel. This is a key milestone for the refurbishment of the unit.

The FPSO is now back at quayside, and we're working on the refurbishment of the topside, preparing for the new module to arrive in Q3. That's new boilers and produced water module.

The idea is to start commissioning activity during the summer, we commission in stage and we can ensure that we will be ready on time for March '27 sailaway. We also plan to get ANP, the Brazilian authority, to audit the FPSO end of the year, we have some time to take their comments into the work we are doing in China and fix all snag list before we leave the quayside.

The jackup in Dubai. This is a picture taken two weeks ago where we were doing the first two legs extension.

We're using one of the highest cranes of the world, this is the tallest in the Middle East. I've been actually on top of the leg, it's a bit scary to get there.

We are finishing this leg extension in June. We will be testing what we've done, we will jack to the top, and then we are preparing to go to the dry dock.

In parallel of this activity, we are refurbishing all drilling equipment, most of the critical equipment have been dismantled and sent to OEM, and they will start delivering during the summer. Cranes, BOP, drawworks, all this is being refurbished, getting ready for drilling.

Of course, the situation in UAE has changed from late February. We have closely monitored the situation for our people first.

We have plan in place should the situation deteriorate, and as well, we have had to follow closely all the logistics, some equipments had to be rerouted to other port in the region. Far, we managed to get all the supply to come to Dubai.

The other work we are looking at is the final towing to Brazil. Of course, Hormuz Strait is closed now, and it will be difficult to pass, but we are already talking with the HLV companies and trying to maximize chances to be able to leave, and so this is a work ongoing to make sure that we don't get any delay.

This is the overall plan and how it's getting together in 2027. FPSO will be towed to Brazil from March '27 during 90 days, the FPSO will arrive just before summer, and we have a couple of months of hook-up and then commissioning.

The wellhead platform will arrive in Q1 '27 in Brazil, and the plan is to install subsea template and then spud the first well. The idea is to have two wells ready when the FPSO is commissioned so that we can make first oil with two wells.

The flowlines are on time, they will be delivered in UK in late '26, and we plan to install them from Q2 next year. We are finalizing the tender for the installation vessel now in Brazil, being ready for chain, the mooring of the FPSO, and the SURF installation.

The drilling, we will start in April '27 when the template is installed, and it's a six-wells program. Each well is around 53 days, we will finish early '28 the drilling program.

This first phase of Maromba is 12 wells, we are drilling six well from next year, and then we will pause and then drill another six wells. This is not the final development.

We see a lot more potential on Maromba, and one potential is carbonate. Carbonates have been produced on Peregrino and Polvo as well.

We want to use our wellhead platform to appraise those carbonates. This is finger shape reservoir you see on the illustration, and if we are successful, we could replicate our development model with additional platforms that we could install and keep a longer plateau on Maromba.

Now I will update you on Namibia on Kudu. Kudu is a gas field that was discovered in 1974.

There was eight wells drilled in Kudu, and five encountered hydrocarbons. This is 1.5 TCF recoverable resources, and we've been doing a 3D seismic acquisition that allowed us to drill an appraisal well end of last year that encountered a petroleum system, and we discovered liquid hydrocarbons.

The Karras-1 allow us to understand better the reservoir, but we've seen that we will need more appraisal program to be able to develop Kudu. Given this is not our core business to do this long appraisal program, we want to open a data room to bring in a partner to be able to do this program.

Also, we see Kudu as very well located in the Orange Basin with all the other discoveries. This is a gas reservoir that could be a great hub for LNG and power, and so we are working on some potential development plans having Kudu as a hub.

This is the update for Namibia, and I will hand over to my colleague Thomas.

Good morning, everyone. It's a pleasure to be here today.

It's another exciting quarter for BW Energy. We have two big FIDs, we're keeping fairly busy.

With the current state of the macro environment, I think it's fair to say we feel pretty invigorated about our strategy, as well as maybe slightly vindicated in our position as a growth-focused E&P. It's nice to have such a vast opportunity set of organic growth opportunities that we can deliver on that Brice and Jérôme took us through.

Let's look at some numbers. We had higher oil prices in Q1 that helped the quarter, that converted to an EBITDA of $111 million.

Q1 net profit was at 33, and we also reduced our guidance a little bit on the production side, as Brice mentioned. This was because of a optimization of the rigs on MaBoMo Phase 2.

We pushed two two production wells in '27, put forward two appraisal wells. This will allow us to then effectively drill these wells sooner in a success case, negative for '26, positive for Dussafu as a whole.

More importantly, we had two new FIDs at Bourdon and Golfinho. This raises our long-term production outlook to more than 100,000 barrels a day by 2028, which we are excited about.

We've also been quite busy on the financing side. We closed another sale and leaseback of the Jasmine rig.

We signed a term sheet for the wellhead platform, the long-term wellhead platform for Bourdon, and we also executed our accordion option on the RBL on Dussafu, which adds $100 million in liquidity next quarter. Moving into the presentation, starting with the current quarter and then moving to the long-term outlook.

Production in the quarter was the same, 2.3 million barrels, same as Q4. Sales was slightly up, that is really because we sell our cargoes in kind of 4 500 to million barrel parcels.

Some quarters, it can slip into the next. Oil price was higher, $79 realized oil price, up from 62.

That's really a function of we sold about half our barrels early in the quarter when oil prices were low, and we sold the other half later in the quarter when oil price was high, so that resulted in 79. Revenue side, higher oil price and more sales puts us at $173 million.

Let's take a look at our cash flow bridge here. We opened the quarter with $151 million in cash.

Operating cash flow before working capital was $87 million, that was largely in line with the EBITDA. Working capital change probably worth mentioning what's going on here.

We had a lifting at the end of the quarter where a substantial part of that was pushed into the following quarter. We also had an underlift position in Brazil, inventory accruing at $104 per barrel, which was the oil price in March, which added to this.

On the investment side, we invested $126 million in Maromba and Golfinho Boost primarily, but that was as planned, and we also drew down some debt to support those financing activities. That leaves us at $161 million in net cash at the end of '26, and liquidity of $333 million.

Probably worth mentioning that, I think Carl alluded to it, in addition to liquidity, we have about $350 million in undrawn project finance facilities across the Maromba wellhead platform and the FPSO, and next quarter we're adding $200 million in addition between the RBL and the long-term lease, worth noting. Turning to the balance sheet.

I think the graphs show a pretty clear story. We're leveraging the balance sheet to support our growth phase.

Our interest-bearing debt has gone from 300 a year ago to now 800. That's according to plan, that's what we said we would do a year ago when we were here.

Leverage ratio is increasing, naturally. A lot of these investments are of course EBITDA that's coming '27, '28, '29.

Book equity is increasing. You can see the equity ratio dropping a little bit, again, a natural function of a growth phase.

We're adding to the denominator, total assets, which is then awaiting profit coming in '27, '28, '29. Liquidity, I think we've largely covered.

Moving to the debt stack. You can see at the end of the quarter, we had now $1 billion in debt.

That is across seven highly diversified financial instruments, mostly are bank-based. They have low costs, and they're quite efficient and long term.

I think probably worth mentioning is a couple of things here. Firstly, that we've structured our debt so most of our amortizations are happening after Maromba first oil, and a significant part of that again is very long-term infrastructure-based financing with 7- to 12-year amortization profiles.

In addition, we've added some debt through the quarter, like we mentioned, $80 million on Jasmine, as well as $200 million coming next quarter that's not currently reflected here in additional liquidity. Next, I'd like to spend a couple of minutes on how we think about our capital allocation framework.

We have three tiers in order of priority. First is high-return growth investments.

We have a very large organic opportunity set of fully operated opportunities with an IRR ranging in 30, 40, 50% at $60 oil price that we feel compelled to invest in. Secondly, we have a target to optimize our capital structure, and to be specific on what we mean here.

We have a baseline of efficient long-term infrastructure financing that we intend to keep, it improves our economics, it's long term, it's flexible. We have the other part, which is quite a bit of revolving credit facilities, either through RBL or on corporate level, which we want to repay after Maromba first oil.

Once we've done that, then we have the firepower to keep investing in new opportunities as they come up. Lastly, we want to return excess cash flow to shareholders.

We have a framework today where we can pay 50% of net profit as dividends after Maromba first oil. We think this is pretty straightforward, and it's really what drives our decision-making day to day.

Next, as we called it a strategy update, I felt compelled to make a slide that kind of explains how this all fits together. I think I see key three structural advantages that sets us apart.

Number one, we can acquire proven reserves at an attractive entry price. There's not a lot of other oil companies our size that play in the greenfield space, we're left mostly alone, which means we don't have a lot of competition.

Also means that whether oil price is $50 or $150, you can still acquire barrels in the ground at a relatively low price. In Maromba as an example, to date, we've paid $0.30 per barrel 2P, and by the time we get to first oil, we've paid roughly $0.90 per barrel 2P in acquisition costs.

Secondly, we're a full-cycle field and infrastructure-capable company. I think what is worth focusing on, and Carl did as well, is really the infrastructure: being able to manage, operate, deliver the infrastructure really sets us in a unique position when we develop new fields.

It allows us to create efficient field developments that minimize cash at risk and also maximize returns, and set up this phased approach is really where we see quite a unique opportunity set. Also in terms of how we finance the infrastructure, which is really how we unlock the greenfields through the financing as well.

We've developed what we think is a creative, low-cost infrastructure-backed financing model, and I can take you through how that worked on Maromba as an example. Starting at the unlevered case, we have a 35% IRR at $60, that's already very good, or I think Jérôme said world-class returns, which I agree with.

We then added the FPSO financing, and the FPSO financing is interesting because it really relates to the redeployment of infrastructure. When we take a redeployment versus a newbuild or a new conversion, it's mostly pipes, steel, repair, life extension, boring work, but it's shipyard work, which increases the local content of the project, which then enables ECA financing.

That's export credit agency based financing because of the high local content. Countries try to get you to their country to do their project, and they provide an insurance wrap around it.

That then allowed us to finance the project 80%, 9.5 years door-to-door at SOFR plus 2.8% margin, which is competitive in our business. On top of that, we've created a greenfield infrastructure financing model with Chinese leasing houses.

This has been something we've been working on for many, many years. It was always a core idea behind the BWE strategy.

Now we're delivering on that. In total, we have a very, I would say, repeatable model.

We've done it on Dussafu, we're doing it on Maromba, and now we're about to do it on Bourdon. Let's take a look at our project pipeline.

This is an extended pipeline. It shows really everything that we plan to do with what we already have.

On the green side here, you can see these are projects that we have FID'd or sanctioned that we are executing on. On the gray side, things that are coming, I think we've covered a lot of that.

The green side, it represents 222 million barrels of net reserves to BWE. These are our investments that have a portfolio NPV zero breakeven of about $40 per barrel, which we think is quite strong.

I think a key takeaway here is you can see in Gabon, we're pretty much drilling for the foreseeable future, and in Brazil, we're doing the same, we're ping-ponging between Golfinho and Maromba for the next few years. This really reflects our company's value buckets as you can see.

Moving to our sources and uses. Yeah.

We have, on the left-hand side, we have our sources; on the right-hand side, where we're going to spend it. We're focusing on Maromba first oil, we did that also last year.

It's life before and after Maromba first oil, and Maromba is a little bit closer today than it was a year ago, we're 18 months away. The reason we do that is because after Maromba first oil, we're pretty much self-funded, and this graph becomes somewhat irrelevant at that point.

Until then, we've added Bourdon and Golfinho FID to our uses. We've added the financings that we discussed, and also the ones that we're planning to add next quarter.

I think a key takeaway is that we are covered at $60 per barrel long-term oil price. With these new FIDs, I'd like to show you a new slide that we've included that includes our phasing of capex.

I think first thing to note is we've increased our guidance from 500 to 600 to 600 to 650 off the back of the two new FIDs on Golfinho and Bourdon. I think it's also worth noting here that all these projects in this capex pipeline have a payback of about 1 to 2 years after first oil at $60 per barrel Brent for each respective project, strong capex spend follow through.

In terms of growth and investments, I always like to think quality over quantity, but BWE is brimming with quality, so. Onto our production outlook.

With the additional FIDs, we are now above 100,000 barrels in 2028, and with the additional wells, we'll be keeping it that way for a few years. In 2027, we're doubling our production due to MaBoMo and due to Golfinho Boost.

In '28, we're doubling again, with Maromba coming online with 60,000 barrels a day. Then Bourdon and Golfinho is really creating this run room here.

Then I think we've talked about the upsides and appraisals that we're also working on through further exploration at Dussafu and work on Golfinho, etc. The next slide looks at how this translates into free cash flow generation for the company.

It's a new slide we've added to highlight the significant value creation that's coming up in the company. It compares our enterprise value as of a few days ago sitting at 2.4 billion with free cash flow at various oil prices.

Or to pick a particular one, but since the red line kind of lines up well with the $70 case, you can see at $70 oil price, the company pays itself back within 5 years. We think this is a pretty solid investment case, of course.

That concludes the outlook section. Let me just recap the updated production guidance for the year.

There's been several revisions. We've talked about the production is due to optimization on MaBoMo Phase 2 and a delay to a vessel on Golfinho.

On the unit opex, that's naturally increasing: production down, opex goes up. There's also some effect from higher oil prices.

Golfinho is exposed to higher gas price, which is a function of oil price, and both fields are exposed to diesel. Obviously, that's disproportionate to the increase in our revenues, it is what it is.

Capex we covered. G&A is unchanged.

Then onto the investment case. Just to repeat it, BWE is a resilient company.

We have a diversified growth model. We have more than 600 million barrels of reserves and resources that we are either executing on or will execute on.

We're currently executing on projects that will bring us from 25,000 barrels a day to 100,000 barrels a day by the end of 2028. That's with a portfolio return of more than 30% IRR at $60 per barrel Brent.

With the free cash flow generation that we just looked at, that will repay the company in about 5 years at fairly reasonable oil prices. With that, thank you, and back to Martin for Q&A.

Yes. Great.

We will start with questions from the audience and then move on to questions online. Anyone online, you can just start sending in questions, and we will take them in the end.

Maybe we start from here, right? I have a helper here in the audience, too, so.

Great.

Teodor Sveen-Nilsen, SB1 Markets. Congrats on two FIDs, looks really promising.

Just want to ask, you talked about sustained production of more than 100,000 barrels after 2030. If you could give some more colors on how you're going to fight decline, which exploration prospects, which appraisal wells, that will ensure no decline or low decline after 20 2030?

A second question, that is on financials. Thomas, you mentioned $125 million change for capital, which definitely hit the cash flow this quarter.

How much of that is related to the late lifting, and how much should we expect to reverse next quarter? Final question, that is on dividends.

You previously talked about dividends after Maromba first oil. You didn't say anything about that now.

Could you just comment on how you think around potential dividends or buybacks in the future?

Maybe I can start in the reverse order perhaps. I think on the dividend side, we mentioned it in our capital allocation framework.

Post-Maromba first oil, we have a framework to do up to 50% of net profit as dividends. That's something we intend to do as long as we don't have an abundance of 50% IRR projects to deliver on.

That follows the plan, and we've been consistent on that since the IPO, really. It's just taken a bit longer than planned to get Maromba going.

On the working capital adjustment, I need to get back to you on the exact split, but it will mostly be reversed due to the lifting and due also to the underlift position in Brazil. I'll get back to you on the exact split.

Carl, do you want to take the question about delivering 100,000 barrels long term?

I think what we tried to illustrate is Dussafu, or offshore Gabon, is an extremely oily area, and I think we have managed, through the appraisal activity we've done, to unlock or to understand of course, you don't always find oil, but we now know that if we have a thick salt layer, we have oil, as long as we have a four-way closure. We do see significant upside.

This has revised our understanding of the Greater Bourdon area, where we see a lot of opportunity, and we now install an asset there, which then will allow us to appraise and put in production consecutively. The next, and that's why we have reworked our drilling schedule, is to step out to Walt Whitman.

Again, we know there's a discovery, it's already been done long time ago, but nobody could unlock the area. Now we can unlock that area, and we reshot the seismic, we're reprocessing it.

Again, we are very, very confident about the outcomes. It doesn't mean that every drilling we'll make will be a success, but there's so many targets, and we now understand the subsurface.

We are very confident about Dussafu. We see a little bit the same happening on Golfinho, and I try to mention, when you take over something like Golfinho with 20-year-plus of history, there's a lot of data to digest, and it's taken our team quite a bit of time to go through everything and catalog everything and get a full perspective.

We knew there were other discoveries with DSTs, with everything, but now we have had the time and opportunity to step through everything, rank it, and structure it. What we see is extremely promising.

From our way of thinking, we see potential, and don't take us as plus 1 billion barrels, but we see a 1 billion barrel potential that's the potential prize of Golfinho. It's a huge potential.

It doesn't mean everything will come in, but with the discoveries already made, we're looking at 2 300 million barrels, and then we can kind of go from there. When you are in an oily area, you find more oil.

The more you drill, the more you understand, the more oil you find. That's what we're saying.

We are extremely pleased with our assets.

For me that Namibia is maybe not the key to sustain production above 100,000 barrels per day?

We are keen to try to unlock Namibia in the same way, but we do realize that the exploration game, or the appraisal game, if you like, because technically we're doing appraisal in Namibia as well, because there is a discovery and we have a production license, it's a bigger game than we prefer to play, because every well is about $100 million, and if you want to do drill stem test, you're talking $100 million plus. In Namibia, we're thinking more could there be potential partnerships?

The other reason is there's a great potential for associated gas. Associated gas is complicated to monetize unless you have gas in addition.

If you have pure gas fields, that's easy to monetize, because you can produce gas and monetize gas. Associated gas, you don't like to try to monetize the gas, as well known from the North Sea, because you really want to run it on oil, not on gas, and that's complicated, because anything you do with gas is commitments.

It's either power station commitments or LNG commitments. Having a swing producer in a big associated gas play could be very valuable.

We're kind of looking to see if other operators in the region could have similar ideas. We know from the press that there's been discoveries, we know they're very gassy.

I think it's a reasonable punt that it will be a gas play in Namibia at some point. We think we could play a part in it, but we think maybe this is an area where it's partnerships.

That's why we're doing a data room to see if we can get dialogues going.

Thank you.

Steffen

Evensen from DNB Carnegie. Three questions: on Dussafu and Adolo, could you remind me just the production capacity on the FPSO and what's your ambition here for sustaining plateau now with the Bourdon Phase 1 and 2 and Walt Whitman?

My second question, on Golfinho, seems to be somewhere gas coming out there, wondered what the offtake agreements are and what kind of gas prices you could realize there. On the long-term sort of 100,000 barrels per day plus, could you provide some color on the capex required to sustain that level, normalized capex, if we assume BWE is going to some sort of normalized territory within that time?

Thanks.

Would you like to take that? Yes.

On the first question, on the nameplate of Adolo, we've done some study, and we can produce more than 50, actually, would be the nameplate so far. We can produce more than 45, and we think we can reach a plateau at 50, all the technical study have been done.

No limitation on the topside of Adolo so far. Bourdon first phase will be between 12 and 15,000 barrels a day, with three initial wells, but we will maintain the plateau with the Phase 2.

We want to start Phase 2 in '29, and we have more than 10 wells in the pipeline of the Greater Bourdon area, 10 targets on top of the three wells that we will put online in '28. We hope that by the end of '29, early 2030, we will have the 12-slot producing from the Bourdon area if the appraisal happen to be successful.

What was the last question?

Question on gas offtake.

Gas offtake, we own the pipeline, which is a great value in Brazil, because we can sell gas onshore. We are actually working on a sell and purchase agreement with companies on the market in Brazil, and we cannot communicate today the terms, but we are working on it at the moment.

On long-term capex, maybe T1...

Just to kind of cover that. I think we've said this before, what we import at is about 10% of Brent, you can kind of assume what we'd export at is roughly around the same price for the gas in Brazil.

In terms of capex, it's a good question. We haven't done that exercise yet, been focused on our project, so.

Having a mix of subsea developments as well as exploration as well as dry tree, it's hard to kind of pin it down to specific number to achieve a exact production. What was the question specifically, on the company or was it on Dussafu?

In total capex

to keep that production level.

At Dussafu or BWE?

Oh, total.

In total, sort of just some sort of normalized cash flow number is what I'm trying to get at,

right. No, we'll have to get back to you on that one.

Yeah.

Basically, to maintain the production, actually in Brazil, we'll have Phase 1 of Maromba with six wells, then Phase 1 of Golfinho with three wells, then Phase 2 of Maromba with six identified wells, then we'll have Phase 2 of Golfinho that we already identified with three additional wells. That will continue like that.

After Phase 2 of Maromba, we'll appraise the carbonates of Maromba that we will penetrate actually in Phase 1, we'll have a flavor of it. It's going to be the same process in Gabon.

The good thing in Gabon is we have already the infrastructure, and in Brazil as well, the additional cost would be more drilling costs than infrastructure costs because the infrastructure we have in Gabon and Brazil can accommodate more production.

Great. Thanks.

I think you can take a look at this slide with the investment outlook that obviously reflects then the projects that's been sanctioned, and then beyond that, we'll have to add some investments, I think, to keep it going.

Yes. With that...

Vidar Lyngvaer, Danske. Thank you so much for the presentation today.

It's been a thorough walk-through, appreciate that. I wanted to touch upon the Maromba and the potential execution risk there.

You mentioned Strait of Hormuz is clearly closed. You want to have a sailaway of the wellhead platform there in late 2026.

You're talking about with heavy-lift contractors to mitigate that risk, but how can you mitigate it if it's closed? Surely, if we get to late Q4 and Strait of Hormuz is still closed, we have bigger problems in the world, but how much time do you have to contract that before starting to...

You have to remember one thing: we're Chinese. Our rig is owned by the Chinese and our heavy lift will be owned by the Chinese.

We're going to be Chinese when we go out the Hormuz.

Excellent point. If there is a delay, you have a lot of capex on Maromba, how should we think about potential capex overruns if there is a delay into 2027 for the sailaway?

I think the biggest risk of delay I agree we shouldn't just laugh Hormuz away, but we do think that we should be able to transit Hormuz because of our somewhat peculiar nationality. We think the bigger risk is in actually getting started and getting all approvals in Brazil.

That's traditionally the risk. We have spent a long time reviewing every FPSO project and every other project that we have been able to get data on, and what has been their issues, why have there been delays in approvals.

Of course, we try to cover everything we can. We have run a sensitivity of six months we can easily sustain.

If we get more than six months, then we will be I wouldn't say in trouble because... Releasing pack.

Depends again on oil price, etc., going forward, of course. It becomes tighter if it's more than six months, to put it that way.

Our sensitivity is six six months is kind of in our plan already, up to six months.

Great. Appreciate the color.

Just if I may add, we want to start the drilling in April '27 to make first oil in September. Even though we would have the rig to come a bit later, we could still manage to do first oil next year, but maybe only with one well.

Basically, yeah, we may have a bit of delayed production, but not fully delay project.

Thank you. That concludes the questions from the audience.

We have received some questions online, too. Perhaps, Brice, could you just go through the plateau production at Bourdon Phase 1 and talk a bit about Bourdon Phase 2, how we anticipate taking FID on that?

Yes. Plateau production, three wells, from 12,000 to 15,000, as I said.

Then we will trigger Phase 2 in '29, and we have 10 additional opportunities in the pipeline for the Greater Bourdon area. All these wells will come online as we appraise the Greater Bourdon area.

Yep.

What makes the Bourdon development simpler compared to MaBoMo, and why did you go down this road?

Yes. We try to leverage the asset that we have in Gabon.

We have additional power capacity on Adolo, it was cheaper to send the power from Adolo. If you want to generate power on Bourdon, you need to have a process to separate the oil, the water, and the gas, take the gas, use the gas to produce electricity.

Then it comes with a very expensive platform. The idea is to use the existing facility that we have, we will send the gas directly to Adolo, process the gas, and produce electricity, and send the electricity directly on the wellhead platform of Bourdon.

It's not very expensive to pull an additional subsea cable to MaBoMo, and actually that's going to be quite a good saving in diesel consumption, and we will reduce as well the greenhouse gas emission of the whole field. On the manning, we have quite a strong platform on MaBoMo with enough people to operate the platform of Bourdon.

The idea is to install boat landings and use crew boats to transfer the crew off MaBoMo to operate the Bourdon wellhead platform. Every morning, the team will go there to operate the platform, but we will use the existing team we have already on site and optimize the opex of the field.

Good. Maybe just to round off Dussafu area, there's a question regarding the option exercise of the Adolo FPSO in 2028.

Is that included in the capex guidance?

It's not included. We have a purchase option of $100 million...

Guidance is to 2026,

we have that's not included because it's in 2028. It's subject to agreement with BW Offshore, so...

Yeah. Logically, if the field delivers as this trajectory, then it will likely be more profitable for us to take the purchase option relative to paying a tariff and bareboat rate.

Yeah. We'll come back to that at later.

Some M&A questions. On M&A in greenfield versus brownfield, you're taking a contrarian approach by leaning into greenfield projects while most of the market has gravitated towards brownfield opportunities.

Has that gap in appetite started to narrow? I'm sure you've got a finger on the pulse when it comes to most recent developments in the M&A market.

Gap narrowed? I didn't quite...

Gap between brownfield and greenfield market.

I don't know. It's an interesting question, but I would say we're kind of alone in the greenfield space, while we see that the brownfield is getting increasingly crowded.

In particular, I would say brownfield is now also the arena for local, indigenous companies. That these days get financing from the traders at a totally unprecedented level, and the traders have a lot of money, they've obviously made a killing in the market lately, and they are very active supporting local, indigenous companies.

We see the brownfield market as crowded. Yep.

The greenfield market as very open. There's not that many greenfields in the market, that's true.

You have to find them. Yep.

Perhaps also allude a bit to what is the vision for BW Energy for the future regarding exploring other countries, and also give a status on the Angola acquisition?

I think we can say that, yes, we have a strategy, but, we also have other strategies. We're not really we are participating in land drilling in Namibia, we're not moribund by a particular strategy.

We're cognizant of what we're good at, of of course, if it is offshore, if it's if it's some involves assets that we are very familiar with, we are good, we know what we know. We're not particularly good at operating on land because we don't operate on land, but I think strategically, if we saw an opportunity, we would still go there.

We're not We're more driven by the opportunity and than we're really driven by a set strategy, I would say. We are yeah, we would look at anything with interest.

We have also looked at other other areas of the of the world, like Far East, but we just haven't found the right opportunity. We're picky about the opportunity, but we're not really picky about where.

Good. One final question on hedging: to what extent will you hedge the Maromba production?

I can take that one. We will not hedge Maromba production until we get to first oil, because that would be speculation.

Once Maromba is producing, we may follow our current company policy, which is to hedge about 40% of our net entitlement in the next 12 months, and then 25% the following 12 months, plus minus.

All right. Thank you.

Oh, one more question here.

A very quick one on M&A: is it a prerequisite that assets would have to be operated, or could you be partner as well?

Yes, we could be partner as well. We prefer to be operator.

Of course, given the right opportunity, if we saw a pipeline of development opportunities where we could play active role, we could also consider to be a partner. Again, we're quite flexible on strategy.

We're okay to be opportunistic. All right.

Thanks.

All right. That concludes the presentation.

Thank you for showing up here today, and thank you for attending online. Yeah.

Thank you so much for your participation and interesting questions. Always enjoyable to do this face-to-face, have a very nice day.

Thank you.