Aker BP Stock

Good morning, everyone, and welcome to Aker BP's second quarter presentation. It was a quarter of strong operational execution and robust financial results. Production averaged 384,000 barrels of oil equivalents per day and operating cash flow was $3.1 billion. And we have raised the lower end and narrowed our production guidance for the year.

Our major projects remain on track with important milestones across Yggdrasil, Valhall PWP–Fenris, Skarv Satellites and Johan Sverdrup Phase 3. At the same time, we continue to strengthen the portfolio for future growth, including through a new strategic collaboration with Equinor. We also maintain a robust financial position with $6 billion in available liquidity and an unchanged quarterly dividend.

Operationally, this was a quarter shaped by seasonally high level of activity with continued high efficiency across the portfolio. Production was lower than in the previous quarter, mainly due to planned maintenance at Edvard Grieg and Ivar Aasen combined with normal quarter-to-quarter variations. Despite these planned impacts, production efficiency was 94%, a very strong performance by industry standards. Production costs increased to $8.8 per barrel, mainly reflecting planned seasonal activity across the portfolio, including maintenance at Edvard Grieg and Ivar Aasen, diving operations at Alvheim and well intervention activity at Valhall. Lower production volumes also increased the reported unit cost. Emissions intensity was 3.1 kilos of CO2 per barrel, mainly reflecting lower volumes in the denominator.

Aker BP remains among the global leaders in low emissions oil and gas production. Johan Sverdrup is a world-class field, combining large scale with low operating costs, lower emissions and excellent safety performance. In the second quarter, our share of production averaged 214,000 barrels per day, supported by high production efficiency and continued optimization of the field. It remains a key contributor to our cash flow. We are also investing to sustain and extend that production. The subsea drilling campaign is progressing with new infill wells and water injectors, and we continue to mature the next phases of the field.

Phase 3 sanctioned last year is on plan. The subsea templates are installed, drilling starts in the fourth quarter and production is scheduled for the fourth quarter of 2027, while Phase 4 is being matured with potential start-up in 2029. We also recently concluded the redetermination process initiated in 2025, following an updated assessment of the field. This resulted in an increase in Aker BP's ownership by 0.15 percentage points, resulting in a net participation of 31.72%.

Let me now turn to our development projects. In December 2022, we sanctioned 10 PDO projects of which 5 subsea tiebacks have started production. And in total, we are over 2/3 completed with the entire project portfolio. These projects are adding more than 800 million barrels of resources and will contribute to lifting our production above 500,000 barrels per day in 2028. Several visible milestones were delivered in the quarter, and before going into the details, I would like to show what that progress looks like in practice.

[Presentation]

Such pictures truly make me proud and happy, and we made great progress in the quarter. You just saw that the 2,500 tonne Hugin B topside was safely lifted from the barge and installed on its jacket last week. And with that, the first top side is now in place at Yggdrasil. Hugin B is a normally unmanned wellhead platform tied back to Hugin A.

Also at Yggdrasil, another major milestone was achieved this quarter with the completion of the power from shore system, clearing the path of the installation of Hugin A towards the end of the year. I would like to extend my gratitude to all our project teams, alliance partners and other suppliers who have contributed to making this happen, from engineering and construction to offshore execution and marine operations, these achievements reflect the dedication, expertise and teamwork of the entire one team.

At Valhall PWP–Fenris, we are now preparing for the next offshore phase. Hookup of the Fenris top side has commenced, and the Valhall PWP topside will leave the [ yard ] at stored and be installed offshore in late August. As Yggdrasil and Valhall PWP-Fenris move through the final construction phase and installation phase, we are actively managing the remaining scope to support safe and efficient completion.

For Yggdrasil, we are investing more in the final onshore completion work to ensure that the Hugin A platform is as complete as possible before sailaway. This reduces both execution risk and the remaining offshore work. For Valhall PWP-Fenris, the updated estimates mainly reflects a larger remaining offshore scope, including hook-up and completion activity. The additional activity is reflected in our updated investment estimates, which are now around 6% above the previous estimates. But most importantly, Yggdrasil and Valhall PWP-Fenris remain on track for first production next summer.

Skarv Satellites is our most advanced project this year and is now approaching start-up. It ties 3 discoveries, Alve Nord, Idun Nord and Ørn back to the Skarv FPSO, extending production from infrastructure we already operate. Drilling and completions of the wells is finished. The subsea installation is complete, while commissioning continues on the FPSO. Start-up remains on track for late August.

With Yggdrasil and Valhall PWP-Fenris on stream, our production is set to increase by around 35% from 2026 to 2028 and support cash generation well into the 2030s. At the same time, we continue to build the next set of opportunities through increased recovery, maturation of discoveries, targeted exploration and active portfolio management. Transaction package agreed with Equinor in May is a good example of how we are going to do this in practice.

Let me take you through some of the key elements. The first element is Ringvei Vest in the Troll-Fram area of the North Sea. This is a subsea cluster development plan as a tieback to the existing Troll infrastructure. It brings together several discoveries in the area, including Kveikje where Aker BP already has a 19% interest. Through transaction with Equinor, we established a 90% ownership position across most of the Ringvei Vest area, giving us a strong foothold in a development expected to contain around 240 million barrels of gross resources. The strategic logic is very much in line with how we think about the value creation at NCS. Discovered resources, nearby infrastructure and a coordinated development concept that can turn smaller discoveries into a larger, more efficient project.

The second piece of the puzzle is the wider Frigg area around Yggdrasil. Last year, the Omega Alfa discovery confirmed oil in the eastern part of the old Frigg area. We are now preparing further exploration drilling next year to better understand the full potential of the structure with a clear objective of finding additional oil volumes that can be developed at Yggdrasil. For the transaction, we will acquire a position in the U.K. license adjacent to the Norwegian acreage. This gives us exposure to a larger part of the structure and creates a more balanced ownership position on both sides of the border. This matters because any future development will need to be evaluated across licensed boundaries and across the border. For Aker BP, the strategic logic is clear. Yggdrasil is not only a major project, but the new hub in an area with significant remaining potential.

The third element is Wisting. Wisting is one of the largest undeveloped discoveries on the NCS with around 500 million barrels in recoverable resources. It is a long-term opportunity and the project has made good progress through the recent maturation phase, moving towards a concept select. As a part of the transaction with Equinor, we reduced our ownership to 27.5% from 35%. For Aker BP, this is a disciplined portfolio move. We retain meaningful exposure to a major resource while reducing our capital commitment ahead of the next decision points.

Before I hand over to David, let me share a few thoughts on exploration. Exploration remains an important part of how we build future growth, and our approach is targeted and disciplined. Over time, we aim for around 80% of our activity to be near existing infrastructure, either as single tiebacks or as a part of future cluster developments. The remaining 20%, it's typically a high impact exploration with stand-alone potential in new areas.

This year's program is particularly weighted towards infrastructure near targets. These barrels can often be developed faster with lower incremental cost because they build an infrastructure and operating positions we already know well. In the second quarter, we completed Tonjer and Carmen. Tonjer is an attractive addition in the Johan Sverdrup area while Carmen is promising, but will require further appraisal.

The third quarter will be our most active exploration quarter this year. Looking ahead into next year, we are preparing from an even more active program, including the Frigg area around Yggdrasil.

With that, let me hand over to David, who will go through the financial results in more detail.

Thank you, Karl, and good morning, everyone. The second quarter was another strong financial quarter for Aker BP. High realized prices, all-time high operating cash flow and the transaction package with Equinor supporting more profitable growth in the years to come. Production, operating costs and project schedules are tracking our full year plan. And cash generation in the first half of the year strengthened materially compared with recent periods.

Now let me start off with our achieved oil prices. The quarter was characterized by a strong physical oil market, particularly in the early period before prices somewhat normalized towards the end. Front month Brent, which is the benchmark most often referenced in the media averaged around $97 per barrel, while Brent dated, which is more relevant for our realized prices, averaged around $104 per barrel.

As shown in the bridge on the right-hand side, we also achieved strong premiums on our crude qualities. Combined with some negative timing effects, this lifted our realized oil price to $110 per barrel. Including NGLs and condensate, our realized liquid price was $108 per barrel. In the second quarter, production averaged 384,000 barrels of oil equivalents per day, bringing first half production to 391,000, well within our full year guidance.

Due to underlift in the quarter, sold volumes were slightly lower, averaging around 376,000. Together with the strong realized prices, this resulted in a total income of $3.7 billion for the quarter. Oil and liquids represented 86% while gas and other income was 14%.

Looking briefly at the income statement. Total income was 22% higher than in the first quarter. Unit production cost was $8.8 per barrel, and as Karl mentioned, the increase mainly reflects the phasing of planned activities in the summer months. We expect lower unit cost in the second half and our full year guidance of around $8 per barrel remains unchanged. After exploration expenses of $47 million, EBITDA for the quarter was just shy of $3.4 billion. In the quarter, we recognized an impairment of $625 million related to other intangible assets at Valhall. The impairment was driven by lower short-term oil and gas prices and updated cost profiles and is offsetting the large impairment reversal we had on Valhall in the first quarter. The methodology and assumptions are described in Note 7 to the report. As a result, net profit was $521 million or $0.82 per share. Excluding impairment charges, earnings per share was $1.15.

Moving from earnings to cash. The second quarter was very strong. Operating cash flow amounted to $3.1 billion, an all-time high for Aker BP. This primarily reflected higher income and positive working capital movements, partly offset by higher tax payments. After cash flow to investments of almost $1.8 billion, free cash flow was $2.10 per share in Q2, up from $0.30 in the previous quarter. This strong cash flow generation supports our financial flexibility and is a natural bridge to talk about how we allocate capital. And the framework is unchanged. A strong balance sheet comes first. It gives us flexibility through the cycle and is the foundation for long-term value creation.

At the end of the quarter, we had $6 billion of available liquidity, up from $5.4 billion 3 months ago, while our leverage ratio improved to 0.55x, down from 0.69 at the end of the first quarter. From this foundation, we invest in high-quality projects that drive future cash flow and dividend capacity. This includes Yggdrasil, Valhall PWP-Fenris and the higher return tieback portfolio.

Over the next 2 to 3 years, we expect production to grow by around 35% from projects that have an expected payback time of 1 to 2 years. And lastly, we returned capital to shareholders through a predictable growing dividend, currently at $0.6615 per share per quarter or $2.65 for the full year, up 5% from 2025.

Zooming in on our investment plan. All our projects are making good progress with several very important milestones confirmed this quarter. And we are particularly glad to see that both big Yggdrasil and PWP-Fenris remain on track for first production next summer. As Karl explained, we have updated our investment estimates to reflect the remaining scope required to complete the projects, including offshore hookup and completion work.

For Yggdrasil, we now expect total investments net to Aker BP of $12.5 billion to $13 billion pretax compared to our previous estimate of approximately $12.1 billion. The increase mainly reflects additional activity to complete more work onshore before sail away and support efficient project execution. For PWP-Fenris, the updated estimate is $7.3 billion to $7.6 billion pretax compared with approximately $7 billion previously. This mainly reflects a larger remaining offer scope, including hook-up and completion activity.

At the midpoint of these ranges, the increase is around $1.1 billion pretax or approximately 6% compared with our previously communicated estimates for the ongoing PDO projects. We expect roughly half of the latest increase to materialize in 2026, with the remainder spread over the completion period. The majority of the investments are eligible under the 2020 tax regime. And as a result, the after-tax cash flow impact is estimated at around $200 million over the next 2 to 3 years.

Let me then bring this together in our updated full year guidance. As mentioned, production averaged 391,000 barrels of oil equivalents per day in the first half of the year, in line with our expectations. With half of the year now behind us with strong performance, we lift the low end of our guidance range and update the full year production guidance to 380,000 to 400,000 barrels per day. Production cost was $8.2 per barrel in the first half of the year, impacted by maintenance activity in the second quarter. This is in line with our plans, and we still expect around $8 per barrel for the full year.

2026 remains our peak investment year. We invested $3.5 billion in the first half and reflecting the updated estimates for Yggdrasil and Valhall PWP-Fenris, we now expect full year CapEx of approximately $6.8 billion to $7.2 billion pretax. Exploration spend is $161 million year-to-date. The program is somewhat back-end loaded in 2026 with several exciting wells coming up. We still expect exploration spend of around $400 million pretax for the full year and abandonment around $100 million.

With that, let me hand back to Karl for some concluding remarks.

Thank you, David. To conclude, this was a strong quarter for Aker BP with robust production, high efficiency, strong realized prices and record operating cash flow. Our major project in Yggdrasil and Valhall PWP-Fenris remain on track for first production next summer. The updated investment estimates reflect active final phase execution with additional onshore completion work at Yggdrasil and a larger remaining offshore scope at Valhall PWP-Fenris. At the same time, we are strengthening the portfolio for exploration, increased recovery and selective transactions.

In short, we are delivering today, progressing the projects that will lift production from 2027 and building the portfolio for profitable growth into the 2030s.

We will now take a short pause before opening the Q&A session. And as usual, to participate, please use the Teams link on the webcast page. And if you prefer to listen only, please stay tuned and we'll resume in 1 minute.

[Break]

Okay, everybody, welcome back. And I am assuming there are, as usual, quite a lot of questions.

There are. And the first question today comes from Tianhong Bi from Citi.

Yes. The first one is on shareholder returns. Last quarter, you guys kind of hinted that if the oil prices stay high, you will revisit the dividend policy. Oil is now trading at $85, your liquidity has improved substantially. Deleveraging seems to be on track, and your peers have raised their return frameworks quite recently as well. So is it time for you guys to reconsider your return framework as well?

Second question is on CapEx increase. Can you clarify the split between additional resources versus spending to protect first oil? I think last time with a similar increase, it was 1/3 additional resources versus 2/3 scheduled protection. Is that still roughly the same right split?

You want to start on shareholder returns, David?

Yes, I can do that. So I think the starting point is our capital allocation priorities. They remain firm, Tianhong. All the value creation that we have in Aker BP will be return to shareholders at one point. And then I think the last quarter has really shown us that oil and gas prices are quite volatile. And we are, of course, also currently investing in profitable growth that will significantly increase our production and also our cash flow generation over the next 3 years. The policy framework, it sort of favors a resilient and growing dividend through this investment cycle. And the ambition is to grow the dividend by a minimum of 5% per year.

And in the past, we have also increased by more than that. For 2026, the dividend is -- we've been guided 5% up from 2025 and that should also be your base case. And then I think we'll come back to 2027 and beyond at our capital markets update in February as normal.

Thank you, David. And on CapEx, we are approaching the finishing line on this project. That means that we have I would say, a fairly good and significantly more advanced understanding of the remaining risks. So of the CapEx guidance that David just talked about, the midrange includes about a 10% contingency of the remaining CapEx. And the way to look at this is that there is a certain set of risks and risk elements that are now associated with the remaining operations. So the lower end of the guidance, that would probably mean that we have been able to mitigate and alleviate quite a lot of art risks, whereas the upside is including somewhat some of these risks that may or may not occur. And then a lot of this is impactable by Aker BP, but some of it is also non impactable.

As you move offshore and you move into a situation where you have logistics, you have flotels, you're also more exposed to things like weather, which are factors that we cannot impact. So what we have done this time is to focus on the start-up in summer of 2027 and put some more robustness around the investment program to make sure that we deliver on that start-up. And as I said in my presentation, the projects are on track. Several milestones have already been delivered. We have started up power from shore, that started up but completed. We have installed Hugin B, and we have now fixed the date for both the Valhall PWP topside installation and also the installation, which will happen in late August.

The next question is from Teodor Sveen-Nilsen from Sparebank 1.

Two questions for me. First on, again, on CapEx, I think I understand that most of the increase is related to keeping your schedule. And I'm just curious in the scenarios you're forced to complete the projects without any CapEx increase, how would that have impacted first oil?

Second question, that is on, by the way, congrats on several good deals here. On Ringvei Vest, how should we think around the net production contribution to Aker BP?

I'm not sure I understood the question, what would happen if we were forced to...

Sorry about that. And just wondering, if you did not increase CapEx, I assume you will still be able to reach some kind of first oil, but how would that have impacted or would it impact the timing of first oil?

That is a relatively hypothetical question, Teodor. So the point here is that as we are progressing into these projects, we have seen somewhat lower productivity in the final stages of construction which have been compensated by some more resources, which are part of this.

And then we have also increased somewhat the robustness of the offshore scope, particularly related to Valhall PWP. These are measures that we would have done almost regardless in order to protect the schedule. That is the most important thing. And then the increase -- you may think that it is large or you may think that is low. And my view on this is that it is relatively modest compared to the overall scope. There's actually really nothing dramatic. It is simply the fact that we are moving towards completion. And then we are adjusting as necessary to make sure that the plants are as robust as we can possibly make them.

What would happen if we didn't do that? Well, I don't think I'm going to answer that. I think every prudent operator would have done the same in this case.

Then the production impact on Ringvei Vest. Let me come back to that when we provide guidance and the updated profiles of -- as we usually do in the Capital Markets Day in February. I don't think I will speculate on that at this point in time.

Then it's Sasikanth Chilukuru from Jefferies next in line.

I had 2, please. The first 1 was going back to Ringvei Vest. The development concept is agreed. I was just wondering what are the next milestones or what kind of time line should we expect, especially related to the investment decision or maybe even the start-up, an indicative start-up time.

The second was on the realizations. I suppose that you had these crude premiums come through in 2Q. Just wondering how you're seeing these play out right now as we speak and your expectations going in 3Q as well?

Yes, you want to touch on Ringvei Vest...

I can do that. So on Ringvei Vest, as you mentioned, the concept to Troll has been agreed between all the partners and the different licenses that goes into this cluster development. FID is planned for late next year, I believe. And then production from this development, you should expect that to be in the 2030s. So this is production that will support our profitable growth in the next decade.

And I believe your second question was related to the fiscal oil market and realized prices, if I was correct? And as mentioned in my presentation, we have seen that the tightness in the market has come somewhat down. The most elevated prices was in the middle of the quarter. So we have seen a normalization, but we are still, of course, seeing the impact of the war in the Middle East. And of course, the volatility related to that situation is very hard to predict. So I will refrain from trying to do that.

That's good. That's exactly what you were supposed to say, David. So thank you.

Are we done, Sasi?. Can we move on to the next caller? Next caller is Alejandra Magana from JPMorgan.

You have active portfolio management as one of the key pillars supporting the next phase of growth in your slides, and you recently established your collaboration with Equinor and did an initial set of transactions aimed at improving ownership alignment and supporting development. Should we view this as a preferred path for portfolio management over the foreseeable future? And should we think about this as primarily accelerating delivery of your longer-term production ambitions or increasing the likelihood of ultimately achieving them?

And my second question is on production. As you look across the second half of the year. What are the key swing factors within the revised range and what would need to go right for production to finish toward the upper end?

Okay. Thanks. Excellent questions. So let me start with a few reflections on the M&A or you call it, longer range. I think for a period of time now in Aker BP, we've had a very, very strong focus on 2 main factors that is delivering high-quality operations with high production efficiency, excellent safety and excellent progress on the projects. And then the second one is making sure that this project portfolio that we decided back in '22 with nearly $19.38 billion or whatever was executed. Now we are about 2/3 in, and we have started to let these a bit more. So the way to think about it is that there is a set of opportunities. It's almost like a menu of opportunities that we're looking at.

One of those are organic growth. You'll see more focus on exploration going forward. You'll see more focused call it, exploration deliveries. This year, predominantly focused on, call it, subsea tiebacks, but next year, more balanced, potentially also increasing. Then there's a set of, call it, organic M&A opportunities, whether it's a transaction that we did with Equinor was kind of framing that is, I don't know. We are a bit more disciplined. This was an excellent opportunity for us to increase our exposure in the West of Yggdrasil area and also increase our exposure to the Ringvei Vest area, while taking down some of the exposure in the Wisting areas. Just it was an excellent portfolio optimization.

And then we enjoy this coopetition relationship with Equinor. So that means that we are we are competing where we need to, but we're also collaborating excellently with Equinor on other areas.

And then the final part of this may be bigger type of M&A. You have actually seen all these mechanics being active in the Aker BP history in the past, and you should expect that we will also be active across all these 3 vectors in the future.

When you talk about production, well, the remaining part now that we are almost done with the call it, heavy maintenance season of this summer, is probably mostly impacted by start-up of, for example, Skarv and the initial start-up rates, how fast we were able to clean up the wells, et cetera, et cetera. But again, we feel fairly confident that we will be able to come within the range. And this is also why we're lifting the lower end of the guidance.

So I would say, as usual, we have a fairly good plan and a fairly robust plan for delivering the remaining part of production in 2026.

Then we move on to Victoria from RBC. Are you there, Victoria?

Let's just move on to the next one. Nash Cui from Barclays. Are you available?

Yes, Yes, I'm not sure that the mic here want to speak before me. But anyway, yes, I'm here. First, I really like the video, I'd like to see the Aker BP employees rolling together as a case very nice. Thank you for that.

I have 2 questions, please. The first one. One of your Norwegian peers recently announced that they are going to grow their medium to long run NCS production by 100,000 barrels a day, which is quite a lot. I wonder how does this Aker BP's view on your future growth plan? And are you concerned about CapEx inflation in the medium term?

And then my second question is I see Aker BP as one of the best engine companies at deploying technology, including AI. It has been a few quarters since you started some of your AI initiatives. I wonder if you could talk about what has surprised you the most so far.

Yes. So first of all, thank you for the comment on the World Cup championship. I think this is one of the events at least in my lifetime that have really [ congealed ] the nation, and it's unbelievable how effectful that has been. So even the Aker BP employees are pitting in and growing. So that's good.

And then on the growth, I think what other companies do or do not do not necessarily impact how we think about it. So as I was -- have been quoted on saying quite a few of these quarters. We have started to raise our gates on the, call it, the next round of growth after these projects that are now in the process of being executed and completed. The directors are, as I just stated to Alejandro, maybe, is organic growth through exploration, focused exploration. It is M&A growth through smaller transactions, and there might also be other bigger transactions that would be a part of this.

We have a very clear ambition to produce above 500,000 barrels well into the 2030s and that hasn't really changed. We've had that ambition for quite some time now. And then, yes, a useful reminder that we haven't talked a lot about technology in the last few quarters, that we need to do something about that, David, but let me just give you a very kind of high-level impact. We are in the process of actively deploying artificial intelligence across Aker BP on many different levels.

What has surprised me the most, probably the fact that this isn't really about technology deployment. It is about reconstructing the work processes. I no longer believe that the technology in itself will be a key competitive differentiator. It is about how you actually restructure work. What we're seeing fundamental changes to how we execute engineering work and how we execute repetitive processes.

Maybe the easy example is everything that is going through a sequential set of operations, every step enhancing the value of the information is now much more concurrent and iterative process fundamentally changing how we think about the work processes and the time line of these work processes. And we are seeing compaction in time in orders of magnitude, that is from months and weeks to days and hours.

I continue to be amazed on the speed and the, call it, the capacity of this technology. But a useful reminder, Nash, I can promise you we'll be back with much more next quarter.

This is very helpful. Can I just quickly follow up on the medium-term CapEx view. Do you feel that more competition that NCS will put we'll have a bit of a cost push pressure on your CapEx?

There is certainly a little bit of push on inflation. I don't really believe that, that has to do with, call it, the ecosystem on the Norwegian Continental Shelf. It probably has to do with inflation in terms of such as raw materials, high-end, metals, et cetera, et cetera, which are flowing into the oil and gas industry from other parts of the industrial ecosystem consuming the same raw materials.

So the way we try to kind of counter this is by being more effective, being more clear with our alliance partners on when we need equipment to allow them better time to execute their procurement processes. But we're also looking at our technical specs, whether we can actually come -- do away with a bit of a different set of materials to avoid some of these cost inflations.

And now Victoria McCulloch, we are ready for you.

A couple of questions for me. Firstly, you highlighted you want to acquire the U.K. license for that impacts East Frigg. Do you have any concerns about the U.K. track record for approving oil and gas developments? Could that be of any drag to sort of further tiebacks in that region given the overlap of the licenses?

And then secondly, just following on from the previous question on the inflation of, I guess, breakeven levels. I guess the commentary is that a sign you are seeing some inflationary pressure on breakevens? And can you give us any updated guidance on where you're targeting breakeven levels for your tiebacks and also for Wisting?

Yes. So let me start with the U.K. track record for approving, probably not the best commentator on that topic. There are several possibilities when it comes to field developments there. One of the possibilities are, of course, that we do a sequential field development, basically extending subsea infrastructure from Hugin A and [ Westwood ].

The first one is obviously East Frigg which will be a part of Hugin A [indiscernible] initial development. And then we have Omega Alfa discovered last year. And then next year, we're going to drill into the Frigg main field or the old Frigg main field and also investigate the potential on the U.K. side of the border.

You should assume that we will be quite active towards U.K. authorities to make sure that, that approval process is as speedy as it can possibly be. If we, for some reason, should end up in a situation where the, call it, the red line on the plan runs through the approval process, we might have to consider a different field development or more sequential field development if that may be the case.

Personally, I don't believe that, that will happen, and I sincerely do not believe that, that will happen. When it comes to breakeven, we haven't really changed even though we see some inflationary pressure. We haven't changed our decision criteria, our capital allocation criteria. So that is the same as it's been for quite some time now.

And the reason is that while there is some, call it, inflation on the equipment side, we do believe that we should be able to compress time quite significantly to counter most of it, if not more, of the inflationary pressure by far amongst others, as I said when talking to Nash about the implementation of artificial intelligence and more, call it, systemic processes to come back time. So there are some pros and there are some cons on this. But in the long and the short of it is that we haven't really changed our breakeven criteria.

That's color will be helpful. Just as a follow-up to that then, fault or where's the range of time lines for Wisting from FID to first oil? Where should we think about that sort of coming in as a producing contributor?

Yes. So Concept Select will be later this year. We are targeting FID towards the back end of '27, and then a bit dependent on what kind of concept you should assume 4 to 5 years of construction period from FID to first oil.

All right. Then we move on to John Olaisen from ABG.

A couple of questions, if I may. Firstly, installations of large top sites in the winter season in Norway is usually difficult and risky. Could you tell us why this is not the case for Hugin A? That's question number one.

And number two, Karl, you said that Aker BP will have more exploration focus going forward. In 2026, your exploration spending guidance is $400 million. What should we expect in terms of dollars spent on exploration in the years going forward, please?

Okay. Good. So Hugin A, you're absolutely right. That's a brilliant question, and I love that you ask that question because it gives me an opportunity to do a little bit of technical learning in this quarterly presentation.

So the way -- the reason that this is different is twofold. The first one is the installation method using the pioneering spirit, which was the same vessel as we used on, for example, parts of the installations. And it's almost counterintuitive maybe, but the heavier and more kind of -- the bigger the weight of these installations, the less responsive they are to behavior of the waves on installation.

The second one, and this is a 29,000 tonne top side. So it's right on the border of what Pioneering Spirit is able to not necessarily due to the weight but also due to the size. And then the second one is that we need a very narrow window. So usually, we have quite a wide range of quite a long window where you need weather criterias inside the lifting criterias. Here, we probably need -- yes, the whole lift will probably be done in less than a couple of hours. And from leaving the key to where installed is probably less than a day. So that means it gives us a very different opportunity to install.

The way we have thought about it is that we can install Hugin A probably year round with very high probabilities of meeting a weather window that is fitting within the normal 2-week period. So that is the technical explanation why this is actually doable. It's one of the reasons that we have built it like this is to make sure that we have a lot of flexibility on installation.

Then your second question, I'm not going to provide you with updated guidance on assumed expects in the future. What I'm saying is that you should assume that as we are ramping up the activity levels and now putting more focus on the, call it, next set of opportunities, some of those will actually be starting out as exploration projects. And then we'll come back with more on the, call it, longer-range expectations in February as we usually do.

And if I may, a last question. I was somewhat surprised to see you joining the Board of Ørsted, Karl. Aker BP has been very firm, you're not going to do any renewables. You're going to stick to oil and gas in Norway. That's it. Could you tell us a little bit why did you decide to join us to the Board?

Yes. Yes, obviously, although initiative of our engagement has nothing to do with Aker BP, but it is a fact that there is a lot of what we do in Aker BP, one has to do with project execution and understanding the energy system that is also applicable to the activities that Ørsted is going through. So I'm assuming that the election committee at Ørsted has felt that I had something to provide also to the Ørsted group on these 2 topics.

And now we have one caller left in the queue, and that is James Carmichael from Berenberg.

Slight high level one, hopefully not covering too much you've already been over. But I guess in previous conversations, kind of stated that it's going to be difficult for everyone on the shelf to meet their sort of 2030, 2035 production targets and that may be the NCS is moving into a slightly different phase of competition. I think you said away from sort of risk management announced a bit more elbows out.

Can you just remind us sort of why you think you're a better place to deliver that than your peers? And maybe some thoughts on what the main challenges are that you see in meeting those ambitions?

Well, obviously, as a start of that commentary, it's probably a challenge that will be bigger the further you push out. So I don't really think that 2030 is going to be a big issue. That's just 3.5 years down the road. And we should have fairly good visibility on the performance. 2035 on the other hand, might be more of a challenge. And as you push out time, you're also dependent on factors like yet to be discovered, yet to be decided, technology development, et cetera, et cetera, which are basically the underlying factors of how good you are utilizing the resources.

And my simple observation is just a simple set of summations of the initiatives and, call it, strategic ambitions or what are your visions or whatever you want to call it, that has been communicated in the market held up against the NPD's view on the Norwegian Continental Shelf.

The other way of looking at it is just putting yourself in 2035, add up the numbers from each of these actors and then ask yourself how much oil do you actually need to find in the years before and after to have a reserve replacement rate of roughly one. And if you're going to grow, you need more than one. So that is a simple kind of number scheme.

Why do I believe Aker BP is better positioned? I think there are 3 main factors, and I think I've been over and over again. First, the foundation for any oil and gas company is excellent operations. This is a topic we have spent now, I would call it, 10 years on making Aker BP as efficient as we possibly can. And I think we are proving that as an operator, we are among the most efficient operators of oil and gas fields anywhere on this planet.

And then second, it is about maximizing the recoverable resources out of the asset you have. And again, I think we have demonstrated, first on Alvheim, then on Valhall and now on Skarv, and also Edvard Grieg and Ivar Aasen that we're extremely efficient identifying and building out subsea tiebacks and other IRR targets to make sure that we produce as much as we possibly can over time from these assets.

And then thirdly, it is about developing new oil and gas fields on time and on budget, if possible, with high quality. And again, our track record in subsea tieback speaks for itself. And now our track record in delivering large project is also going to be really, really good. So I think we have the foundation for competing well against any player, also on the Norwegian Continental Shelf.

Then going forward, there are probably also factors like implementation of technology, recruitment of personnel and other moves that are important to us. So I actually do believe that Aker BP has the foundation. We have the capabilities, and we do have the ambition and have demonstrated the ability to utilize those capabilities to be very, very competitive on the Norwegian Continental Shelf. So I'm fairly certain that in this game, Aker BP will come out on top.

And that concludes all the questions from the audience.

Excellent. Thank you, guys. And even though we did not win the quarter finals against England, I still want to wish you all an excellent summer. And as I usually say, to Aker BP, whatever you're doing this summer, stay safe.

Good morning, and welcome to Aker BP's First Quarter 2026 Results Presentation. We entered 2026 with a strong momentum, and it continued in Q1. Production efficiency was 97%, consistently among the best in the industry. Symra came on stream 9 months ahead of the original plan and the broader development portfolio hit its key milestones. And when the oil price moved higher late in the quarter, driven by geopolitical disruptions in the Middle East, our high-performing portfolio enabled us to capture the upside with tailwinds carrying into Q2. We delivered production in the high end of our guided range, sector-leading cost, a significant project delivered 9 months early and realized prices well above what the screen showed.

Let me briefly turn to our operational performance in the quarter as summarized here. Starting with production efficiency, our assets delivered 97% of the theoretically installed capacity. This reflects consistently strong operations across the portfolio. Daily production averaged just above 398,000 barrels, close to the high end of our full year guidance range. Production cost was reduced to $7.7 per barrel, fully consistent with our full year guidance of around $8 per barrel, and we remain among the lowest cost producers in the industry.

At the same time, we continue to operate with very low emissions intensity at just 3 kilograms of CO2 per barrel, reinforcing the quality of our asset base. Together, this underscores the strength of our portfolio and a high degree of operational control. Q1 reinforces a clear message. We are converting our project pipeline of attractive low breakeven project into barrels on or ahead of schedule. This chart shows our production outlook into 2030. Delivery of our major projects keep us on track to reach around 525,000 barrels per day in '28, corresponding to approximately 35% growth from 2026.

Beyond 2028, our ambition remains unchanged to sustain production at around 500,000 barrels per day well into the 2030s. Our ongoing field developments continue to underpin production growth, supported by a disciplined and repeatable execution approach across the portfolio. Over the past several years, we have built an operating model centered around hub development, standardization and alliance-based execution. This is clearly reflected in our subsea tie-back program. This year, production has started at both Solveig Phase II and Symra tied back to existing infrastructure in the Edvard Grieg. Symra came on stream 9 months ahead of the original plan, and it's the sixth subsea project sanctioned in '21 and '22 to start production, 3 tie-back to Alvheim and 3 tie-back to Eiga. Momentum continues at Skarv, where the 3 tie-back projects have now been further accelerated and are now expected on stream in the third quarter this year, almost a year earlier than originally planned.

Across the portfolio, these 9 tie-backs have delivered strong project economics. On average, the project showed an estimated full cycle return of around 50% at a $7 per barrel price, with breakeven prices of approximately $27 per barrel and payback time of around 10 months. These results reflect execution through our subsea and drilling alliances, built on long-term partnerships, early contractor involvement and aligned incentives. The results are repeatable and a competitive position in the subsea tie-back execution on the NCS.

Alongside our tie-back activity, execution continues on our 2 major development projects. Both Yggdrasil and Valhall PWP-Fenris remain on track for first oil in 2027. At Yggdrasil, activity levels are high across the project. And as we move closer to the offshore phase, the main priority is to complete as much work as possible onshore ahead of sail away. For Hugin A topside, sail away is planned in the fourth quarter with focus on minimizing carryover into offshore execution. At Valhall, a key milestone was recently reached with a successful installation of the Fenris topside.

Construction of the PDP top site is progressing at the Stord yard with sail away for offshore installation scheduled for the third quarter. Here too, focus is on productivity and readiness ahead of the offshore execution period. Let me show you what this quarter installation looks like in practice. [Audio Gap] This is large-scale project execution. Together, our tie-back portfolio and the major developments provide a balanced and capital efficient path to growth with material production coming on stream from 2027. We continue to view exploration as an integrated part of our business with its importance reinforced by a broader focus on energy security. The activity was lower in the first quarter, but has now picked up.

In the Johan Sverdrup area, the Tonjer exploration well was completed in early May and confirmed volumes in line with the pre-drill estimates. The data from this well will provide valuable information for future development in the northern part of the area. We are currently drilling the appraisal well at Carmen and have recently spudded Linge. Over time, this work helped ensure that our production base remains competitive beyond the current project cycle.

Thank you, Karl, and good morning, everyone. The first quarter represents a strong operational and financial start to the year. Production cost and project execution are tracking our full year plan and cash flow generation has strengthened materially compared to the previous quarter. I will start with a brief comment on the oil market environment and then walk you through the financial performance for the quarter before closing with a few remarks on cash flow and the balance sheet.

The recent events in the Middle East are causing significant human suffering while also affecting global energy markets. From a market perspective, we have seen oil prices move materially higher since early March. I'd like to spend a few minutes on how this translates into our realized prices since the dynamics this quarter have been somewhat unusual. And what investors see on their screens does not fully capture what flows through to our top line. Aker BP's physical oil sales are priced against Brent Dated, not the front month futures contract that most investors follow. When we agree a sales contract for a cargo, we agree a differential to Brent Dated. The cargo is typically delivered 1 to 2 months later and the final price is set in the 5 days around the delivery date based on the Brent Dated plus or minus that differential. There are 2 points here that matter for how you should think about our realized prices.

First, since March, Brent Dated has traded materially above the front month futures contract. Under normal market conditions, the 2 move closely together. The dislocation we have seen this quarter reflects tightness in the physical market for prompt barrels. The practical implication is that headline Brent prices have understated the price of physical North Sea barrels. Second, the differentials on our own cargoes have increased materially through the same period. And without going into specific numbers, this dynamic provides additional support to our realized prices on top of the Brent Dated effect itself.

Together, these factors contributed to an average realized oil price of $83.5 per barrel in the first quarter. The same dynamics have continued into the second quarter and to an even greater extent. As a result of the contract structure I just described, our average realized oil price in the first month of the second quarter was approximately $127 per barrel. Note that this reflects pricing on volumes already delivered and is not a forecast for the full quarter. If you would like to understand these dynamics in more depth, our Chief Economist, Torbjorn Kjus, has recorded a video presentation that walks through the current market situation in more detail. It is available on our website, and I would encourage anyone who wants more granularity on the physical pricing mechanics to watch it.

Turning to the Q1 results. Production averaged just above 398,000 barrels of oil equivalents per day in the quarter, close to the high end of our full year guidance. Due to overlift, sold volumes were slightly higher, averaging around 406,000 barrels. Total income amounted to $3 billion, supported by a realized liquids price of $82 per barrel and a realized gas price of $80 per barrel of oil equivalent. Unit production costs were $7.7 per barrel. After exploration expenses of $48 million, EBITDA for the quarter was $2.7 billion.

In the quarter, we recognized a net impairment reversal of $522 million, primarily relating to the other intangible assets at Valhall and driven by higher short-term oil and gas prices. This is a reversal of impairment charges recognized in the fourth quarter of 2025. The methodology and assumptions behind this are described in detail in Note 7 in the report. As a result, net profit was $758 million compared with a net loss of $145 million in the fourth quarter of 2025.

Moving from earnings to cash. Operating cash flow amounted to $2 billion. Cash generation benefited from a higher income and lower tax payments with 2 installments in the quarter compared to 3 in the fourth quarter of last year, partly offset by working capital movements, amplified by higher prices in the quarter. Overall, the first quarter demonstrates how our operational execution and cost discipline translate into strong financial performance and robust cash generation.

Let me also briefly comment on our guidance for 2026. All components of our guidance are reconfirmed. Production between 370,000 and 400,000 barrels per day, production cost around $8 per barrel and CapEx of $6.2 billion to $6.7 billion. After Q1, production is tracking within range. Costs are below the full year level and CapEx is in line with plan. In light of the current market situation, I would also like to address the outlook for cash flow and the balance sheet. But before I walk through this slide, I want to emphasize that the figures shown are scenario-based. They illustrate possible free cash flow outcomes under different price paths, and they are not forecasts. Since the strategy update in February, the only change we have made is to lift the assumed average realized oil price in the first half of 2026 to $90 per barrel across the scenarios.

The key outcome is that 2026 has become significantly more robust. And even in a prolonged low oil price scenario of $50 per barrel from the second half of this year and onwards, our leverage ratio is now estimated to not exceed 1.5x. What the scenarios also show is that across a wide range of price paths, our portfolio continues to generate positive free cash flow before dividends. At current strip prices, free cash flow generation is materially positive. And in a lower price scenario, the financial flexibility we have built provides the buffer needed to manage volatility while keeping us comfortably within our investment-grade framework. 2026 remains an investment heavy year with peak activity on Yggdrasil and PWP-Fenris. As these projects come on stream next year, the scenarios show free cash flow generation increasing materially across all the price paths shown.

Now let me then close off with a few words on what this means for our shareholders. Our capital allocation framework is unchanged. A strong balance sheet is the foundation for value creation. On that foundation, we make disciplined investments that generate returns that in the end are distributed to shareholders. Our job is to maximize long-term dividend capacity, and that requires capital and good investments first. Translating this into where we stand today. First, we maintain a strong investment-grade balance sheet with $5.4 billion of available liquidity, providing flexibility through the cycle. Second, we fund the investments that drive our growth,Yggdrasil, PWP-Fenris and the high-return tie-back portfolio. And third, we returned capital to shareholders through a predictable growing dividend currently at $0.6615 per share per quarter.

Going forward, the picture is clear. 2026 is a peak investment year. From 2027 and onwards, as Yggdrasil and PWP-Fenris come on stream, free cash flow generation steps up materially, providing the basis for continued attractive shareholder returns in the years to come. With that, let me hand back to Karl for some concluding remarks.

Thank you, David. Q1 2026 confirm the strategy is working, high production efficiency, sector-leading cost and yet another project delivered well ahead of plan. Our track record on subsea tie-backs lays a solid foundation for future projects. Looking ahead, our priorities remain unchanged, safe and efficient operations, disciplined project execution and an exploration program aiming at strengthening the resource base. Underlying all of this is continued focus on execution, operating, developing and exploring more efficiently year-by-year and translating that performance into sustainable shareholder returns.

We will now take a short pause before opening the Q&A session. And as usual, to participate, please use the Teams link on the webcast page. And if you prefer to listen only please stay tuned and we will resume in 1 minute.

[ Break ]

Welcome back and then I think as usual, we'll just go directly to Q&A. And as usual, the master ceremony is our very own Kjetil Bakken. Kjetil, over to you.

Thank you, Karl. The first caller is Tianhong Bi from Citi. Let's see if we can make the line work this time, Tianhong.

There is a problem with the sound here. Can you hear me?

Now we hear you. Yes.

Okay. Perfect. Karl, you highlighted the strong economics of your recent tie-backs in your remarks with $27 a barrel breakeven and very, I mean, quite attractive IRR, which screens better than your peers, for example, targeting $30 to $35 range breakeven on similar projects. Could you please help us understand what is driving that differential?

And then second question, can I just get your latest thinking on your capital allocation strategy under higher oil prices, particularly that balance between shareholder returns, deleveraging and investing for growth in the medium term?

Yes. excellent. Thank you, Tianhong. So first of all, the presentation we've done concluding on the $27 breakeven is taken into account actual as well as projects that are yet to come on stream. Our, call it, decision criteria has remained unchanged. What this reflects is an ability to outperform the plans we made at the original decision point. But you're absolutely right, it is my view too that over time, we have consistently now built both a track record and a repeatable system to develop subsea tie-backs significantly better than most of our competitors.

On your second question on the capital allocation, the capital allocation policy remains firm. We have seen periods with high oil prices and periods with low oil prices and our communication to the market has been the same. All value created by Aker BP will, at some point in time, come back to the investors. How that distribution is, remain unchanged. If the oil price remains high, there might be a need to think about our dividend policy. But at this point in time, we favor stability as we have done in situations with low oil prices.

All right. Then the next caller is James Carmichael from Berenberg.

Can you hear me, okay?

We can hear you.

Just to, please -- So just thinking about the realization points that you made in terms of data versus futures, et cetera. I'm just wondering if there's anything we need to think about for tax purposes with the norm pricing environment in Norway or if that's all captured in those comments? And then just looking further out beyond '28 once these developments are online, just a reminder, I guess, on how you think about sustaining production at sort of or above 500,000 barrels a day. Is there enough in the hopper to keep that going organically for 5, 10 years? Or is it likely that we'll see Aker BP look to maintain that level via M&A?

You want to do the...

On price, Karl?

The dated versus futures versus nonprice?

Yes. No, I can do that. So I don't think there's anything in particular that you need to think about when it comes to tax related to the, call it, widening of differentials. So the norm price is set based on the average of the achieved differentials across the different sellers on the shelf for the different qualities. So nothing in particular there that's worth mentioning.

Good. And then on the sustained production, on Slide 4 in the presentation that I just went through, you can actually see the distribution of the profile into the 2030s. And as you see, the gap, call it, of previously FID projects have been closed in the last couple of quarters. That is an indication that the strength of the hopper is healthy and that we're continuing to close that gap up to 500,000. And then to be in excess of 500,000, you will need either some more exploration success or M&A. That is among the reasons why we continue to focus on exploration. And even though this quarter has been a little bit slow in terms of exploration, we are still very focused on exploration as a key enabler to bring barrels into the hopper. But the short answer is very healthy pipeline with good breakeven and solid economics and backed by a repeatable execution strategy that we have demonstrated also in this quarter.

Next caller is Teodor Sveen-Nilsen from Sparebank 1.

Karl and David. Two questions from me. First, on summer maintenance this year. Is it tempting to push back some of the maintenance given the high prices we see?

Second question that is just a follow-up on the 500,000 barrels per day question. And I want to ask about the listing. What is the status there? And what kind of work is going on? And how should we think around the timing of the FID?

Okay. On summer maintenance or turnarounds or other, call it, production reducing maintenance. In reality, what we are doing is that we are creating a long-term plan where we are minimizing the production impact on maintenance regardless of what the oil price may or may not be in any specific quarter. That means that there is not a lot of scope to change that program as we've already tried to focus on the optimization of that versus production.

We do run through it 1 more time, not because the oil price is high, but because there is such a pressure on the physical market that we do want to make sure that towards our customers, physical customers in the market, we do what we can to supply the market. But I'm not going to say that, that will incur significant changes as of today. On this thing, the plans remain the same. The operator is progressing with concept studies. My expectation is that we will reach a concept select sometime this autumn. And then we will probably end up in a decision sometime next year.

Yes. All right. Then the next question comes from John Olaisen from ABG.

If my count is correct, you have 5 top sites that are planned to be installed this year. The first one, Fenris was installed in April, as you showed a nice video. I wonder is it possible to give an indication of when you plan to install the remaining 4 top sites being Hugin, A and B and Munin and the second one of Valhall, please?

Good. Absolutely right, of course. We did install Fenris this quarter, also installed the Hugin B jacket. And then the 2 remaining, call it, smaller ones, which is Munin were not really small. It's 9,000 tonnes. But -- and then you have Hugin B. My guess is that somewhere in the autumn, that will be installed. It's a bit related to how we think about finalization of the offshore program, and there's a lot of flexibility in that lifting window at the moment. So not really a completion issue. It's more a planning issue, mainly driven, I would say, John, by the fact that these are actually supposed to be unmanned. So we don't really want them to be out there for too long without hooking them up and powering them for maintenance and conservation purposes. Then the 2 major ones, that will be, again, dependent on the actual offshore program as we're working on this summer. My guess is towards the fall, we will install PWP and then in -- towards the back end of 2026, we will install Hugin A. But again, it's more of a totality and making sure that we have the most efficient offshore program at this stage.

All right. I just wonder when you say late 2026, is it like a deadline where the window is shutting?

For Hugin A, you mean?

Yes.

No, not really. Almost counterintuitive here. So Hugin A is a topside of 29,000 tonnes. It's to be installed with pioneering spirit. And the fact that the unit is so big, it means that the weather we can actually install in is better than if the unit was significantly lighter. So in a way, this installation policy gives us a lot of flexibility in actual installation timing.

How about the smaller ones when you say this autumn? We all remember the adverse weather problem with the Hugin episode where the deadline seem to be late August for sail away.

Yes. But that was a completely different setting. So the smaller ones will be more exposed to weather windows, and it's quite clear that they need to be installed prior to, let's call it, the significant worsening in weather towards the late autumn at least.

And just to specify the 2 large ones, then you mean Hugin A and the last 1 at Valhall. Is that correct?

That is correct. That is...

My final question. I understand there might have been -- or I have heard that the hotel strikes has impacted some of the yards in Norway. Is that something you've seen? Or is it not -- should we not worry?

We're not worried. We may have -- I'm -- my job is to be worried. So I'm worried all the time for everything. But in reality, yes, there is strikes going on that is affecting the kind of the catering and camp activities in a number of industrial sites. We have found solutions for the yard at Stord. So activity is ongoing as normal, and I don't expect any disruptions due to the current situation.

The next caller is Victoria McCulloch from RBC.

Firstly, on CapEx, the run rate certainly seems to be at the top of guidance. But as you talked through, there's a lot of key activities certainly in the second half of the year. Can you just talk through what the moving parts are that get you to, I guess, to the range and how that -- I guess, how that splits? And could it accelerate in the production plan or has accelerating the production from the Skarv Satellites push you towards the top of that range?

And secondly, on the unitization at Yggdrasil, can you just talk us through what's happened there this quarter?

I can do the planning, the assumptions, and then I'll let you do the numbers, and then we'll touch on unitization afterwards. Yes. So you're absolutely right. When construction is going on at full blast at Stord, there is about a little above 10,000 FTEs in rotation. Obviously, as you are moving towards sailaway, those numbers will come down, meaning that the burn rate will come down as well. So there's a natural consequence in terms of activity as you're moving from the, call it, onshore activity to the offshore activity. And then as you're ramping up offshore with the drilling rigs and all the associated activity, the kind of the spend level comes up a little bit, right? So that's basically the planning consequences of why you can't just do Q1 and multiply it by 4. And then you can touch a little bit on the actual numbers, if you want to.

Yes, I can do that. I think overall, the cost performance has been strong in the quarter. And when we look at the plan, there's no reason to change the guidance. And the guidance range is what the guidance range is for a reason that there is, of course, some uncertainty related to the development. And then I think you also need to mention, of course, that the Norwegian kroner has strengthened towards the end of the first quarter and is also strengthening into the second quarter. And that could give some pressure on the costs measured in dollar terms. But as we have talked about many times before, we are well positioned with FX hedging. And to remind you of the numbers, we have 70% to 90% of our NOK exposure hedged at rates between NOK 10.5 and NOK 11 per dollar. And you can actually also see the effect of that this quarter with $80 million in realized gains on our FX derivatives alone.

So that's the current situation on costs. So we don't see a sort of a specific need to change guidance based on where we are today, but we are following, of course, the situation. Unilization?

Yes. So very simply put, East Frigg had a different ownership profile than the Frigg Gamma Delta unit. The previous cost estimate or call it CapEx estimate was assuming the Frigg Gamma Delta ownership. So when you join these licenses together in a unit, there is a pro rata concur to be done, which at this point in time, resulted in a slight influx of capital to Aker BP. So it's basically a mechanical process where you take all the different licenses and join them into a unit.

And then I can add also, Karl, that this was, of course, agreed ahead of the actual sanctioning of the East Frigg. Now in the first quarter is when the actual accounting effect of this has happened and also the true contract. And that, of course, has been part of the planning for 2026 and onwards. So that's, of course, included in the CapEx numbers in our guidance and also the production profiles that we have put out. I think that's very important to mention.

It is essentially just the actual consequence of the unitization occurrence that you see now in the Q1 accounts.

All right. Then the next caller is Naisheng Cui from Barclays.

I have 2, please. The first one is Aker BP had a very strong operational delivery, and you have done a great job bringing many projects forward. I wonder what has prevented you to upgrade your P50 production guidance for this year? So that's my first question.

My second question is also on your future M&A growth strategy. I wonder, have the improved oil price curve changed your view on Aker BP's approach to M&A activities from here? What is your view on the NCS M&A outlook?

So first, on project delivery and production guidance. So first of all, I absolutely do agree with you, Naisheng, and thank you so much for making that comment. The project delivery has been strong. But in reality, my expectation has been just that, that Aker BP will continue to deliver excellent results, both in terms of production and in terms of project execution. So while it is -- I'm extremely happy to see those plans coming to fruition, it is not like something that is coming as a, call it, surprise to us. We have seen this excellence in execution, as you also pointed out, developing over quite a few quarters at this point in time, meaning that when we push out our P50, we actually do expect the Aker BP deliveries to be excellent.

On M&A, my view on the Norwegian Continental Shelf is that there is a significant amount of opportunities. It is quite clear that there will be a consolidation game on the Norwegian Continental Shelf, almost at least long term, almost regardless of what the oil price may or may not be. It is quite clear that the operators with the highest skill set, most robust execution strategies and the lowest, therefore, breakeven and other fiscal moves will succeed. It is also quite clear that going forward, you will see a different profile on the Norwegian Continental Shelf, dominated by subsea tie-backs and dominated with what I would call more complex reservoirs like high pressure, high temperature tight. This is the reason why Aker BP has, over a long time now built an extremely robust subsea tie-back. I wouldn't call it factory, but value chain with the alliances, a digital execution model and the whole apparatus around that, that is now demonstrated that at least in my mind, is -- yes, I'll probably be a bit cautious, but no, I'll say it, I believe it's actually industry-leading. And we've also done the same now on expanding our skill set. Fenris is a demonstration of our capability to enter into the high-pressure, high temperature. Again, a decision made amongst other parameters for that reason. On tight, we have been working with tight oil and tight gas on the Norwegian continental shelf for more than a decade now on the Valhall field and surrounding entities. So I do feel that we are extremely well positioned on the NCS -- both with -- when it comes to organic, but also inorganic opportunities. My view essentially hasn't changed.

That's great, Karl. Can I ask a follow-up question on your -- on the first question because I find it really impressive that you brought forward some projects even 9 months ahead of the original plan. That's really impressive. I wonder what have you done right here? Can we see more examples coming?

So 2 -- I think there are 2 different factors. So let's take the Symra or tie-back first. Two main drivers here, I would say, excellent results and modifications on the platform at Ivar Aasen, great drilling results and on-time subsea deliveries. No quality incidents. Those are the main components. On Skarv Satellites, I would say I have never seen this kind of performance on an offshore modification that we've seen on Skarv.

And this is actually the model we're now taking forward with what we call the next-generation modification alliance with Aker Solutions. Second, I would always use the word exceptional drilling results, which again has made sure that the well potential is delivered well ahead of time. And then again, also on Skarv, extremely well-performing subsea alliance. So overall, even though when you go into these projects, there's a little bit of contingency and you try to take into account that there might be events, it's been an almost flawless execution on these 2 projects.

Very helpful. Thank you so much. The next caller is Alejandra Magana from JPMorgan.

I don't think we have sound.

No. Let's move on to the next while we wait for Alejandra. Sasi Chilukuru from Jefferies.

Can you hear me?

Absolutely Sashi. Good to see you.

Yes. My question was on Johan Sverdrup. We saw a 5% year-on-year decline in 1Q, high production efficiency, optimization and new well contributions all offsetting natural decline as it's been highlighted. My question was whether this was indicative of the overall decline rates at this field for this year?

You want to do...

I can definitely do that. I think as we've talked about many times before, the performance on Sverdrup has been great. And the performance we've seen in the first quarter have been in line or even maybe slightly better than expected. So there's no specific news there with regards to that. And again, I think we -- it's worth mentioning every time, Karl, we think that Equinor is doing a fantastic job managing the production of the field. And also, we see the same also with Johan Sverdrup Phase 3 progressing well.

All right. Then we give Alejandra another chance because I think I heard her. Alejandra, are you there? No, there seems to be -- there she is.

Can you hear me?

Yes, we can. Good morning, Alejandra.

I'm glad I finally got this to work. Your 1Q production was strong near the high end of your full year guidance. Should we read this as derisking delivery towards the upper half of guidance? Or are there specific maintenance decline or phasing effects later in the year that keep you comfortable leaving the range unchanged?

And my second question is on Johan Sverdrup. Now that you have both the field center drilling and the Deep Sea Bergen subsea campaign underway, what have you learned so far from the retrofit multilateral wells and workovers and has anything changed in your confidence around the 2026 decline mitigation plan embedded in guidance?

Really good questions. On production guidance, Q1, yes, Q1 was great, high production efficiency, excellent results, robust execution like all of it, but also expected that kind of performance. When it comes to the rest of the year, there is still wells to be put on stream, activities to be carried out. Teodor asked about maintenance, there are some of that as well. So while we had an excellent quarter, we also expected an excellent quarter as we put out the guidance. So I don't really see -- I don't see a material change compared to our plans in Q1, if anything, slightly on the positive side. So I don't see a reason to change the guidance at this point in time. On the Johan Sverdrup activity, David reiterated and I'd like to support that Equinor is doing a great job operating that field. That also goes for the drilling operations and the well operations. The retrofit multilateral maybe slightly better than our expectations, but well within the uncertainty parameters, I would say, strengthen at least my view that we will need to see more of this kind of activity going forward. But again, mostly in line with our expectations.

Then we move on to Anders Rosenlund from SEB.

My first question, you said the ambition is to sustain production around 500,000 barrels a day into the 2030s. But the slide says above 500,000 barrels a day. I don't know if that's just a different way of putting it. My second question is if you could talk about commodity price hedging and the opportunity to buy more puts, in particular on oil price. It seems like you've done some in Q1.

Great, Anders. It's great to hear somebody else in Bergen on this call, too. Well, -- there is, of course, a little bit of semantics on this. So our view is to sustain production above 500,000 well into the 2020s, just to be very clear on that topic. As I said, I do believe that the pipeline is strong. I do believe that over time, we've built an excellent execution strategy and a set of alliance partners that have demonstrated capability to deliver this. I do believe that going forward, there will be more opportunities. We have a strong exploration program to increase this. And I do believe that in terms of M&A, there will also be opportunities. So I'm optimistic -- in terms of Hedging...

Yes. Okay. Yes. So we continuously evaluate, call it, the cost benefit of hedging and you specifically asked for oil puts. I think what we have seen, of course, with the increase in prices, there's also been a significant increase in volatility, which again then means that put options become quite expensive, at least when you look further out in time. So we are continuously evaluating it. And then I think it's worth noting when it comes to the cost benefit of it. I alluded a bit to it when I talked about the scenarios for cash flow generation and also the leverage ratio development in downside scenarios going forward.

And the way that we see it is that 2026 is now significantly derisked when you look at the leverage development in a $50 scenario from the second half of this year, for example. So that, of course, is something that we take into consideration when we look at the value of buying put options.

All right. Then the final question seems to be a follow-up from James Carmichael from Berenberg.

I wanted to ask about the impairment reversal that we saw in the quarter. I think that obviously -- that impairment was only taken in Q4. It's now been reversed on higher prices. I guess just interested maybe to get a bit of color on specifically the assets underlying that and whether we should simply expect that impairment to come back if prices normalize later in the year or early next.

I think the final question is definitely one for you, David.

So we use a consistent methodology when we do the impairment testing, and that is also specifically also document in the notes of the accounts. You are perfectly correct. This quarter, we do a reversal of impairments of other intangible assets on Valhall and that's a reversal of the impairment that we had last quarter. And it's driven by the price increases that we have on both oil and gas. And you can see the prices used in the accounts in the notes, and that is the forward price at the end of the quarter. So this is a mechanical exercise. And I don't want to speculate on what the forward price of oil is at the end of the second quarter. That is too difficult in these times. So I'll leave it at that.

Okay. But in the hypothetical scenario that oil prices did normalize at some point, does that impairment -- we should just assume that mechanically that comes back...

Then we mechanically will adjust the oil and gas price used in the impairment test. And then we will have to see if other developments have reversing effects, but I think you're on to something.

All right. That concludes the Q&A session. Karl, any final words?

No, not really. Thank you, guys. Thank you for excellent questions and for taking the time to listen to us this morning. I do wish you a great day and a safe day, and I can assure you that here at Aker BP, we will continue to do our very best to deliver the same excellent results that we had in Q1. Thank you so much.

Good morning, everyone, and welcome to our presentation of Aker BP's Fourth Quarter and Full Year 2025 results as well as our annual strategy update. I am joined today by CFO, David Tonne, and you will also hear from a few others in the team as we go along. Our agenda today has 3 main parts: First, a review of our operational and financial performance in 2025; second, our strategy update and the priorities that will guide us in the years ahead. And finally, as usual, a Q&A session.

Let me provide the key highlights for 2025. We delivered strong cash flow from operations, supported by consistently high production efficiency across the portfolio. Our major development projects progressed as planned and remain on schedule for start-up in 2027. It was an outstanding year for exploration as we participated in the 3 largest discoveries on the NCS and added around 100 million barrels of resources. We maintained an industry-leading cost and emissions performance. And financially, we kept a clear focus on shareholder returns while protecting the balance sheet and preserving financial flexibility.

With that, let's look at '25 performance in a bit more detail. Full year production for 2025 averaged at roughly 420,000 barrels per day, at the top end of our initial guidance a year ago. The outperformance was broad-based and the production efficiency landed at 96%. I would particularly like to highlight the contribution from Alvheim, where we reallocated processing capacity to Tyrving through a commercial arrangement. This added flexibility and supported production in the first half of the year.

Johan Sverdrup continues to be our single largest contributor to production. The field delivered strong and stable volumes through 2025, supported by excellent reservoir quality, high regularity and very low operating costs. Last year, we took several steps to strengthen the long-term production profile. The retrofit multilateral campaign is progressing well, the second well is now on stream, and the third is being drilled.

There has been a lot of attention recently around Equinor's comments on expected 2026 production, indicating a decline of more than 10% from last year. This should not come as a surprise. The field has produced around half of its reserves. And like any field in this phase, production will, of course, gradually decline over time. This expected decline has been reflected in our company guidance throughout. And we are taking active measures to manage this decline. For 2026, we plan to drill 6 infill wells from the drilling platform, along with a subsea campaign of 3 additional infill wells. We will also drill an appraisal well on the north flank, Tonjer, to assess the potential for a new template in that area.

And then we have Phase 3. This subsea expansion will add 2 new templates and 8 wells. The project was sanctioned last year and is progressing as planned with fabrication ongoing at several sites. Drilling of the Phase 3 wells is set to begin towards the end of 2026 and start-up is expected in the fourth quarter of 2027. Overall, Johan Sverdrup remains a world-class asset that will continue to deliver high-value barrels for many years to come.

We maintain an industry-leading cost level with production cost of $7.3 per barrel, essentially in line with our guidance of around $7. This reflects strong production efficiency, a firm cost discipline, effective execution of maintenance activities and a constant focus on the operational performance. Our emissions intensity was 2.8 kilograms of CO2 per barrel, among the lowest in the industry, and we delivered solid safety results with a low and stable TRIF and SIF.

Keeping our people safe will, of course, always be our top priority. 2025 was also a very active year for our field developments. We often get questions about what this activity really look like, what our teams are doing, how we work on folds, and what scale that lies ahead of us in the coming years. So instead of walking you through every single task, I thought we'd just show you. This short video offers a quick glimpse into the pace, the scale of the activity across the field developments last year.

[Presentation]

We will return to the 2 largest projects later in the presentation, but let me say a few words about the smaller developments, the tieback projects that are also delivering high value. In short, they are performing exactly as they should. Solveig Phase 2 tied back to Edvard Grieg came on stream last week, on time and on budget. Symra, which will be tied back to Ivar Aasen, remains on track for start-up later this year. And the Skarv satellites are progressing so well that we now expect first oil already in the fourth quarter, more than 6 months ahead of the original plan.

2025 was a breakthrough year in exploration. We participated in the 3 largest discoveries on the NCS and added around 100 million barrels net to Aker BP. At Kjottkake, we worked closely with DNO, combining our subsurface insight and fast-track development approach to rapidly unlock and mature discovery. At Omega Alfa near Yggdrasil, we pushed the technical frontier with advanced geosteering, wired pipe technology and long horizontal drilling. This enabled real-time reservoir mapping and turned a multi-target well into one of the largest NCS discoveries in a decade. Lofn and Langemann is also a highly promising discovery, which was enabled by ocean bottom nodal seismic, where sensors are placed on the seabed to provide more precise geological data than traditional surface seismic.

We will return to the topic on exploration later. Now the 2025 numbers.

Thank you, and good morning to you all. As Karl just outlined, 2025 was a year of strong operational performance, providing a solid foundation for continued delivery of our value creation plan. Sustained high production and low operating costs, combined with a relative stable commodity price environment and immediate tax deductions for investments resulted in a record high operating cash flow of around $7 billion. Our development projects remain on schedule for start-ups this year and the next. In fact, the Skarv satellites have now been accelerated into 2026. At the same time, throughout 2025, our 2 largest development projects have increased in size, both in terms of total investments, but also the resource base and expected future production. We will return to this later.

During 2025, we have taken several proactive measures to further strengthen our financial flexibility and Aker BP enters 2026 in a strong financial position with a balance sheet with low leverage and ample liquidity. Lastly, in accordance with our ambition, we increased dividends by 5% year-over-year.

So with that backdrop, let's turn to the 2025 financial results. Earnings ended at $2.8 per share compared to $3.5 in 2024. Importantly, we delivered a strong operating cash flow of $11 per share, up from $10 the year before. This provided a solid foundation for the $2.52 per share in dividends we paid, while also covering most of our growth investments. And finally, we closed the year with a continued low leverage ratio of 0.6x net debt to EBITDAX.

Zooming then in on a few key points from the fourth quarter. Production in the quarter averaged 411,000 barrels per day. With an overlift position of 20,000 barrels per day, more or less reversing the underlift from the third quarter, net sold volumes ended at 431,000 barrels per day. Realized hydrocarbon prices averaged $63 per barrel of oil equivalent with realized oil prices as normal, slightly above Brent. Operating costs came in at $7.9 per barrel produced compared to $7.6 in Q3. The increase mainly reflects the phasing of maintenance activities and production mix.

Throughout 2025, we have, as expected, seen a stable increase in production cost per barrel, driven by the decline in production. This has been amplified by the weakening of the dollar against the Norwegian kroner, starting the year above NOK 11 and ending around NOK 10. As mentioned, operating cash flow for the full year was record high.

Looking at the quarterly pattern, cash flow before tax payments and working capital movements remained fairly stable through the year. With tax now paid in 10 monthly installments, quarterly cash flow will be less volatile going forward, all things equal. Investments in the fourth quarter were $0.1 billion higher than the 2 preceding quarters, with the main driver being the major development projects. The combination of 3 tax installments, a small working capital increase and higher CapEx resulted in a negative free cash flow of $427 million for the quarter or minus $0.68 per share.

Let me also comment on the impairments this quarter. As you can see from the income statement, we recognized impairment charges of $944 million in the quarter. These relate to technical goodwill on Johan Sverdrup, the Valhall and Alvheim areas as well as other intangible assets at Valhall. The main driver this time is lower forward prices for oil and gas at the end of the fourth quarter compared to the end of the third, which reduces the recoverable value in the accounting tests.

As a reminder, technical goodwill is an accounting effect from earlier acquisitions. Because this goodwill is not depreciated under IFRS, we must test it every quarter. And all else equal, as we continue producing from the assets where goodwill was allocated, we should expect noncash impairments over time. When price assumptions move, that amplifies the effect. Since impairment of technical goodwill has no tax deduction, the charges flow straight through the income statement and result in a high reported tax rate. For the quarter, the effective tax rate ended at 137%, and this is entirely driven by the impairment effect.

If we adjust for these noncash items, earnings per share would have been significantly higher and the tax rate would have been much closer to what you should normally expect. And as always, for those of you who want a deeper explanation of technical goodwill and how impairments work in our accounts, I recommend the short video available on our investor website.

Moving on to the balance sheet and recent developments in our financial position. Building financial capacity and ensuring access to capital is a continuous process for us. Over the past years, we have completed several successful bond transactions, which have strengthened our financial flexibility and pushed our debt maturities well beyond the start-up of our major field developments. In October, we continued to capitalize on favorable market conditions by issuing $1 billion in 10-year senior notes maturing in 2035, with the tightest credit spread on a 10-year note ever achieved for Aker BP. To me, this once again confirms that the U.S. bond market and its high-quality institutional investors share our confidence in the long-term outlook for oil and gas, the strength of the Norwegian Continental Shelf and in Aker BP's strategy and value creation potential.

Also in October, we refinanced our bank facilities, a total of $3.2 billion with maturities up to 5 years with options that could extend final maturity to 7 years. This refinancing replaces the previous facilities that were set to mature in 2026. As shown in the chart on the left, net interest-bearing debt increased to $6 billion by year-end. At the same time, tax payables came down significantly to $1.1 billion. In practice, this means that half of the debt increase was driven by the reduction in taxes owed to the state. Our leverage ratio remains low, but as expected, given the current oil price environment and our investment program, it ticked up to 0.6x net debt to EBITDAX at the end of the quarter. Total available liquidity stands at $5.9 billion, where $2.6 billion is cash or equivalents and the rest is our undrawn bank facilities.

Now to round off, let me briefly recap how our 2025 deliverables tracked against our guidance. We started the year with a production guidance of 390,000 to 420,000 barrels per day. As we progressed through the first half, performance was very strong across several fields, particularly from Tyrving in the Alvheim area, which derisked the lower end of the range. We, therefore, raised the bottom of the guidance at our second quarter presentation. Momentum continued through the summer with consistent high performance across the portfolio and importantly, a Valhall with no chalk influx issues for the first time in many years. This gave us the confidence to lift the guidance again in Q3 to the most recent guidance range of 410,000 to 425,000. For the full year, production in the end averaged at 420,000 barrels per day, at the very top of our original range.

On production cost, we guided around $7 per barrel and ended at $7.3. The main driver for ending in the higher end was the weakening of the U.S. dollar versus the Norwegian kroner, moving, as mentioned, from above $11 to around $10 through the year. Underlying costs were in line with expectations and with like-for-like foreign exchange rates, production cost would have ended below $7 per barrel.

Turning to CapEx. As many of you will remember, we increased our 2025 estimate to around $6.5 billion in July. We ended nearly 8% above that, close to $7 billion. The increase was mainly driven by 2 factors: good progress, but also higher spend on the PWP-Fenris project and the same currency effect that impacted production costs. The foreign exchange impact was, however, partly offset by our currency hedging program, which in the third and the fourth quarter delivered realized gains of $13 million, equivalent to a CapEx reduction of around $75 million. Exploration and abandonment spend came in as guided, close to $500 million and $100 million, respectively.

With 2025 behind us, it is time to look ahead. And before we turn to Aker BP's strategy, let me briefly step back and look at the broader strategic context, which really, in my mind, comes down to 2 questions. First, will the world continue to need oil and gas? And second, does the Norwegian Continental Shelf and Aker BP have a role to play.

On the first question, global oil demand continues to be much more resilient than many expected. Much of the growth comes from aviation, petrochemicals and expanding economic sectors that continue to depend on oil, while road transportation remains the single largest source of consumption. Our market analysis points to a continued growth in the global oil demand at least to 2035.

The energy transition is accelerating, but the global demand for energy is growing even faster. We are still adding new sources of energy, not replacing the existing ones. We will, therefore, rely on hydrocarbons throughout the transition and the world is better off sourcing these barrels from lowest emission producers. At the same time, natural decline in existing fields removes a large number of barrels in supply each year, which means substantial new investments is required just to keep the market in balance. If we step back from the short-term volatility, the oil market remains structurally tight.

On the second question, let me start by saying that the Norwegian Continental Shelf is a fantastic place to be for an oil and gas company, not only because of the resources beneath the seabed, but also the environment above it. We operate within a stable and predictable regulatory and fiscal framework supported by high standards for safety and emissions. And we have a world-class supply ecosystem that drives innovation and raises the performance for the entire sector.

According to the Norwegian Offshore Directorate, Norwegian oil and gas production is around its peak today and is projected to decline unless decisive action is taken. The Directorate outlines 3 scenarios towards 2050. In the high scenario, which means significantly higher production and creates significantly greater value for the society, 3 things must happen. First, Norway needs sustained exploration activity that delivers a large number of commercially viable discoveries, both near the existing infrastructure and in the less mature areas like the Barents Sea.

Second, we need rapid technology development to increase recovery both from existing fields and to unlock resources that are smaller and more complex like tight and HPHT reservoirs. And thirdly, we need a continued industry commitment to invest in exploration, in developing discoveries and in improved recovery across the shelf. If we deliver on these priorities, the high scenario is certainly within reach. Norway can continue to develop its resources, contribute to Europe's energy security and create sustainable, substantial long-term value for the society. This is Aker BP's clear ambition and delivering on it will require technology, speed and new ways of working, areas where Aker BP already stands out.

For years, we said digitalization would reshape our industry. Today, that shift is no longer theoretical. It is here, and Aker BP has a unique advantage, a long history of forward-leaning digital ambitions, combined with a scale that lets us move fast. Over the past decade, we haven't just built digital tools. We've built a data connection that connects the whole company, high-quality, structured real-time data. On the top of that sits a future-fit digital ecosystem that allows us to integrate, automate and optimize across exploration, drilling, project and operations. This foundation is what makes everything else possible, including the growth we are aiming for.

We started out by improving analog work processes. Then we digitalized them. And now we are entering a stage where the entire workflows themselves are being reconstructed. Artificial intelligence collapses in traditional processes and gets us to decisions in a fraction of the time. We're already seeing the impact across the business. In exploration, artificial intelligence is enabling earlier and better decisions. In drilling, wired drill pipe, long horizontals and advanced geosteering is delivering world-class performance. And at Yggdrasil, digital twins, autonomous systems and condition-based maintenance are turning remote and low-manned operations into reality. And finally, across operations, AI agents are cutting troubleshooting time, improving uptime and freeing our people to focus on higher-value decisions.

But this is not experimentation. It's a capability. A capability that strengthens our competitiveness, increases our pace, lowers our cost per barrel, and supports the growth journey ahead. It is a differentiator that helps us move from discovery to first oil faster than ever before and do so safely and predictably. And this is why we are so confident about the road ahead, because we're not starting now. We are scaling on 10 years of investment, hard-won experience and a data foundation that many talk about, but few actually have.

The NCS now needs a step-change in productivity. It is, in fact, a race to deliver faster, safer and at a lower cost. And the companies who manage that will shape the future of the shelf. Aker BP is pulling ahead, and I can assure you we do plan to stay here.

Before we move on, let's hear a brief external perspective.

Hey, everyone. My name is Deb Cupp, and I'm the President and Chief Revenue Officer of Microsoft. I am really excited to take a moment to recognize Aker BP for the extraordinary leadership you've demonstrated in AI. You're one of the most advanced users of AI that we've seen and have had the pleasure of working with at Microsoft. I've really been particularly impressed by both the speed and the saturation of your implementation. You're an early adopter of M365 Copilot and Copilot Studio. You're achieving nearly 100% adoption, which is remarkable. Your continued commitment to digital innovation positions Aker BP as truly global leaders in the frontier firm of AI, not just an ambition, but in actual real execution. I also want to recognize the incredible work you're doing across the broader ecosystem with partners like Cognite, SLB, Landmark and Siemens to build and deploy secure agentic workflows that are truly transforming core business processes. This is exactly what it looks like to be an AI frontier firm.

Another cornerstone of our competitiveness is the Aker BP alliance model. Over the past decade, our alliances have helped us remove waste, use resources more efficiently, reduce drilling risk and build stronger, more adaptive team together with our suppliers. This is what has enabled us to reach what we always call as good as it gets in several parts of our delivery chain. But as I just said, the NCS is changing and our alliance model must evolve with it. The developments we are planning for the next decade require even tighter collaboration, more repeatable solutions and far deeper digital integration than ever before.

So we are now taking the next step. We are developing the next generation of alliances where our partners will work even more closely with us, supported by shared data, standardized solution and performance-based contracts. And the goal is simple: deliver faster at lower cost and with higher quality and stay ahead as the NCS becomes more competitive, both for us and our alliance partners. Our drilling teams show how this has come together in practice. We are systematically removing inefficiencies through technology, scale and continuous improvement. And as this chart shows, we are the most efficient operator in the sector.

New technology and innovations such as wired pipe, conductor-less wells, horizontal exploration laterals and dual penetration enabled shallow water drilling are driving step changes in speed, data, quality and emissions. At Yggdrasil, these innovations are expected to deliver around 20% higher drilling efficiency compared to the average, freeing up an entire rig year annually. The results are more value, more prospects that become economically viable and materially lower emissions per barrel.

This chart shows our production outlook to 2030. We expect to reach around 525,000 barrels per day in 2028, driven by the delivery of a major project now under execution. Beyond 2028, our ambition is unchanged, to sustain production around 500,000 barrels per day into the 2030s. And compared to last year, the foundation behind that ambition has strengthened. The business plan beyond 2028, that is the dark blue area on this graph, has grown. This reflects additions across the portfolio, including Kjottkake, identified upsides in the PWP-Fenris area, more tiebacks in the Skarv area, and better reservoir performance in the Alvheim area. Together, these additions have almost closed the gap to 500,000 barrels per day in 2030, and they give us a stronger and more diversified production base as we enter the next decade.

Looking further ahead, 3 levers will shape our post-2030 trajectory. First, the discoveries that are already in our portfolio, including Wisting as well as a broad set of IOR and tieback opportunities around our hubs with the recently discussed Omega Alfa as an addition. Second, a continued active exploration program supported by artificial enabled subsurface tools and innovative drilling methods that raises success rates. And third, selective M&A, strengthening our long-term portfolio and accelerating value creation. Together, these levers position Aker BP to deliver sustained, profitable production way into the next decade.

But first, let's look at the major projects, Yggdrasil and PWP-Fenris, which are the largest building blocks in our growth story right now. And let me start with Valhall PWP-Fenris, because this project is reshaping the future of the Valhall area. We are, in fact, redeveloping Valhall with a new production and wellhead platform that expands capacity and extends the life of the field. At the same time, we are adding gas processing capability that makes it possible to tie back Fenris, a gas discovery, which is an integrated part of the development. The concept is straightforward, a new production and wellhead platform called PWP at the Valhall field center and an unmanned installation at Fenris tied back 50 kilometers to Valhall.

The jackets for both platforms are now in place. The Fenris drilling campaign has been completed and drilling at Valhall has started. Construction of the topsides are progressing at Stord and Valhall. To ensure that we maintain a strong momentum in this critical phase and to secure start-up in 2027, we have strengthened the resourcing at the yards. These measures give the teams capacity they need to keep PWP on topside on track for sail away from Stord in the third quarter this year.

And on the resource side, the development is becoming even more attractive. After an excellent drilling campaign at Fenris, we are adding a fifth well there. And at Valhall, we have added 4 more wells to the plan. In total, these wells are expected to increase recoverable volumes by 30 million to 35 million barrels net to Aker BP, an increase of around 17% from the initial estimates and a good example of how big fields get bigger.

With this, the net investment estimate for the project is now roughly $7 billion, about $1 billion higher than previously. Most of this reflects the actions we are taking to keep the schedule on track, while about 1/3 is linked to the additional barrels. In short, yes, the investment estimate has increased, but so has value. The additional wells are adding material resources, the long-term area potential is improving, and we are still on schedule for first production in 2027.

Yggdrasil is not only our largest ongoing development. It is a defining example of what Aker BP stands for. It brings together technology, leadership, our alliance model, execution capabilities and our commitment to delivering low-emission barrels at scale. The Yggdrasil project is progressing steadily towards startup in 2027. The jackets are now installed at both Hugin A and Munin and the drilling campaign is underway. And topside assembly is progressing on plan at the yards in Stord, Haugesund and Valhall. In Q4 this year, we are planning to install the Hugin A topside offshore, a major and very visible milestone for the project. But that's only a part of the story. 2026 will indeed be an exceptionally busy year for Yggdrasil.

[Presentation]

In many ways, Yggdrasil is the blueprint for Aker BP's future and a glimpse of the future NCS. And it's not just the development concept that points forward. The resource potential around it does as well. Big fields tend to grow and Yggdrasil provides a strong platform for continued expansion. A great example is Omega Alfa, the major discovery we made this summer. It added more than 100 million barrels gross to the Yggdrasil area and moved us significantly closer to our 1 billion barrel ambition for the area. We also see further upside, and we expect to return with more exploration drilling in 2027.

In the meantime, we also have an exciting exploration program lined up for 2026. If I were to highlight one area in particular, it would be our campaign at Utsira High. We start with Tonjer in the Johan Sverdrup unit. It is maybe not the largest project, but it carries a relatively high probability of success. In the second quarter, we will drill Svarteknippa located near Solveig and Edvard Grieg. And this well in together with Freke North later in the year, represent a natural follow-up to the Lofn and Langemann discoveries, aiming at further maturing this play and possibly extending the proven trend. In the same area, we also will drill the Symra Phase 2 appraisal well. Together, this campaign represents a significant opportunity, and it sits at the core of our strategy, how to grow the resource base around our existing hubs.

In the Northern North Sea, I would also probably highlight the Alpehumle well planned for this summer. Located north of Gjoa, it carries substantial value potential and targets the same play concepts as the nearby discoveries such as Cerisa, Ofelia and Duva. But exploration is not just about the next well or the next campaign. It's about how we build long-term advantage. And the way we explore is changing. It's driven more by technology, data and entirely new ways of working.

So let me show you how we at Aker BP are reshaping the exploration workflow. What used to be a slow and sequential process is now becoming a fast, data-driven and technology-enabled, allowing us to test more ideas, reduce risk and make better decisions earlier. First, we are successfully using real-time exploration drilling. Horizontal geosteering, wired drill pipe and ultra-deep resistivity tools gives us real-time insight into the reservoir. Decisions that once took days now happen in seconds. We can test multiple targets in a single run, turning what might previously have been a dry well with shows into commercial discoveries.

Secondly, we are gaining massive AI-powered subsurface insight. Our in-house developed AI tools analyze huge amount of geological and seismic data in minutes, work that would normally have taken days or even weeks. This gives us better prospect selection and frees up our experts to focus on areas where human judgment really matters. An excellent example is in the 2025 APA licensing round. Here, AI really supercharged how we work. Instead of weeks of manual screening, document searches and draft iterations, we use our in-house AI assistants to prescreen data, highlight geological features worth a closer look and pull forward relevant insights from past applications and analog field. On top of that, AI-driven drafting tools help us speed up the writing itself. This enabled our geoscientists to evaluate opportunities faster, improve the geological understanding and deliver a stronger overall application. The productivity gain was tangible and the highly successful APA results reflected it. And this is what AI means for us, practical tools that lift speed, increase quality and the confidence in our decisions.

And then thirdly, high-resolution ocean bottom nodal seismic provides a step change in imaging quality, reducing uncertainty, improving well placement and derisking prospects, particularly in the mature areas where this clarity matters most. Lofn and Langemann is a very strong example of the value of ocean bottom nodal seismic.

So what does all this mean? Well, in short, these innovations compress traditional workflows into something faster and more powerful. We explore with higher accuracy, higher confidence and lower cost, and the impact is already visible in discovery such as Omega Alfa, Kjottkake, and Lofn and Langemann. But this mindset doesn't really stop at exploration. It's the same way we are rethinking workflows that are now shaping are mature and we develop our discoveries faster, leaner and with far better insight. By working as one team across exploration, subsurface and project, we are developing the next generation of project in a far more efficient way.

For many years, Aker BP has systematically built strong and proven field development capabilities through our alliance model, the adoption of new technologies and a relentless push on digitalization. Looking toward the 2030s, the NCS is changing. The resource potential remains significant, but the discoveries are smaller and the reservoirs more complex. To stay ahead, we must once again raise the bar, compress time lines, improve efficiency and turn marginal resources into profitable barrels. And we must keep pushing the boundaries of technology and innovation to unlock the more complex reservoirs and developments that will define the next decade.

At Aker BP, we are now moving to the next level, reinforcing next-generation field developments along 3 fronts. Standardization and proven technical solutions have long been an important part of our projects, reducing complexity and enabling continuity. We are now advancing this approach by scaling standardized, leaner and more repeatable solutions in engineering, well design, modular layouts and equipment. We shorten time lines, lower cost, improve predictability and build portfolios of projects where learning compounds and accelerate performance.

At Aker BP, an integrated end-to-end data flow is becoming the backbone of how we work. Instead of long linear and requirements heavy processes, we use an argue-in approach with rapid iteration, sharper trade-offs and early clarity on value. Rethinking workflows from exploration to first oil and maturing subsurface and development concepts efficiently in parallel, improve value, decision quality and speed. And with one shared data foundation, we can automate workflows and scale AI. Our proven alliance model built on shared objectives, aligned incentives and true co-development with our core suppliers remains a defining pillar of Aker BP. And as we shift to fully data-driven integrated workflows from exploration to first oil, we are further enhancing how we work together as one integrated team across subsurface projects and our suppliers.

We have what it takes, a strong foundation, proven capabilities and the mindset to transform at pace. For next-generation projects, our ambition is clear, to halve the time it usually takes from discovery to first oil on the NCS and drive cost efficiency at similar magnitude, and we are already seeing the results. Take Kjottkake. The discovery was made in March 2025. Shortly after, we increased our ownership by acquiring Japex stake, and we recently became the operator for the development phase. We moved quickly to define a viable tieback concept, subsurface projects and partners, worked in focused sprints, capitalizing on our proven alliance model, simplifying decisions and removing waste in the process. We are now on track for first oil in early 2028, 3 years after discovery. That sets a new pace for the NCS.

By developing the next generation of projects faster and far more efficiently, we will continue to maximize value around our hubs and innovate to unlock new plays, turning the increasingly marginal and challenging resources into profitable barrels. Take Skarv. through developments like Aerfugl and Skarv Satellites, we have already doubled recoverable volumes. Recent discoveries add further upside, and we aim to extend production on Skarv well into the 2040s. Data-driven workflows combined with standardized and lean solutions and close collaboration with our alliance partners allow us to deliver our portfolio of infill wells and subsea tiebacks faster at lower cost and with greater confidence.

On Valhall, recoverable resources have increased sixfold since start-up, and we still see significant potential. With PWP-Fenris, we are now turning Valhall into a long-term hub for oil and gas in the Southern North Sea. And with decades of experience from continuous tight reservoir development on Valhall, combined with a high pressure development on Fenris, we have already taken important steps toward unlocking even more challenging reservoirs across NCS, such as Victoria and Warka, one of the largest undeveloped gas discoveries on the NCS with around 250 million barrels of oil equivalent recoverable.

Technically challenging, tight and HPHT, but a pivotal building block for turning the large tight reservoir potential on NCS into profitable barrels and opening a new play type beyond our current portfolio. Awarded in January, we are already progressing at pace, qualifying technologies, capturing scale effects and improving production rates. The work we are doing today defines Aker BP's capabilities for the decade ahead. It positions us to continue developing the NCS responsibly and competitively. And it strengthens our ability to deliver efficient and low emissions productions for decades to come.

The Kjottkake story is not only about exploration success and fast project execution. It also highlights an important point about M&A, our third lever for sustaining production into the 2030s. It shows that with the right partnership, the right ownership structure and fast aligned decision-making, we can unlock substantial value. Our approach to M&A has been consistent for more than a decade, value-driven, grounded in sound industrial logic and focused on efficient integration, never scale for its own sake. Some examples include the acquisition of Hess in Norway, strengthening our position in the Valhall area and unlocking new growth opportunities.

King Lear added new high-quality resources and paved the way for Fenris. And the combination with Lundin Energy, transforming our portfolio, bringing Edvard Grieg into Aker BP and increasing our stakes in world-class assets such as Johan Sverdrup and Alvheim, creating a more robust foundation for the highly value-accretive developments now nearing completion.

This track record reflects disciplined capital allocation, deep technical understanding on the NCS and a long-term mindset. We will continue to pursue opportunities, but only where we see a clear strategic fit, compelling economics and the potential to create real value for our shareholders.

We are now more than halfway through our 6-year value creation plan launched at the beginning of 2023. It's a plan designed not only to deliver value-accretive growth well into the 2030s, but also strong cash flows and substantial distributions to shareholders along the way. We are progressing well and entered 2026 with a strong financial position, expecting 36% production growth over the next 2 to 3 years and have a lot of exciting opportunities to create significant shareholder value beyond that.

And with that as a backdrop, our capital allocation priorities remain firm. Our first priority is to ensure we always have sufficient financial capacity. That means maintaining a strong balance sheet and ample liquidity, so we can manage volatility, fund our investment program and preserve strategic flexibility. Second, we invest to create value. We continue to allocate capital to projects with strong returns, low breakevens and robust cash generation. Our tieback projects in the Eiga and Skarv area will be completed in 2026, and we continue to invest in our major development projects with start-up in 2027. In addition, we mature and sanction new developments such as Johan Sverdrup Phase 3, the Kjottkake discovery and high-return infill wells to maximize shareholder value. And third, we return the value we create to our shareholders. Our dividend framework provides consistency and predictability. And as our cash flows grow, we remain committed to distributing that value back to investors. These 3 priorities guide every capital decision we make.

And as I've earlier today already covered the financial capacity part, let me turn to our investment program. As Karl has already covered, our development projects are progressing according to schedule. Over the past year, we have updated our investment plan to reflect the latest cost estimates and to include new highly profitable projects. As you can see in the chart, we are now past the peak investment year in our 2023 to 2028 value creation plan. 2026 will still be a CapEx-intense year, but as the major field developments move towards start-up next year, CapEx will come down sharply.

For 2026, we now expect CapEx in the range of $6.2 billion to $6.7 billion. That is roughly $0.5 billion higher than previously indicated, driven by mainly 3 factors. Currency effects, a stronger Norwegian kroner versus the U.S. dollar increases the CapEx when measured in dollars. This accounts for roughly $200 million of the increase. New projects, around $100 million, mainly related to Kjottkake. And lastly, increased cost to safeguard the schedule for Valhall PWP-Fenris.

For 2027 and 2028, we have included new growth investments compared to last year. The most notable additions are Kjottkake and the PWP-Fenris upside program, which includes 5 additional wells. Together, these investments add more than 50 million barrels net to Aker BP from 2028 and onwards. Most of our investments in 2026 and '27 qualify under the temporary tax rules, providing an 86.9% tax deduction. From '28 and onwards, investments get 78% deduction in line with the standard petroleum tax regulation in Norway.

As most of the deductions are realized in the year of investment, it is important to also look at the actual after-tax cash flow impact. And finally, as already discussed, because more than 2/3 of our investments are denominated in Norwegian kroner, our U.S. dollar estimates are sensitive to currency movements. And to manage this, we have proactively hedged 70% to 85% of our planned after-tax NOK expenditures for 2026 and 2027 at an average U.S. dollar-Norwegian kroner rate between NOK 10.5 and NOK 11.

The financial effects of this hedging do not impact reported CapEx. They are recognized as financial items. And as shown in the note to the balance sheet, our current currency derivatives positions were valued at approximately $109 million at year-end. These positions relate to the hedging of our planned Norwegian kroner expenditures. With a 22% tax rate on currency derivatives, the after-tax value is around $85 million. To put that into context, in value terms, this corresponds to roughly $650 million in lower CapEx across 2026 and 2027. As we ramp up production from our new projects and CapEx starts declining, free cash flow will significantly increase over the next 3 years. By the end of 2028, we expect to have generated up to $12 billion in cumulative free cash flow on how oil and gas prices develop.

In turbulent times, resilience matters. We have built financial strength to withstand volatile commodity markets and our metrics remain robust across most plausible oil price scenarios. Assuming a continued 5% annual increase in dividends, our leverage stays comfortably below our internal threshold of 1.5x and well within the bank covenant of 3.5x. Even in a prolonged $50 oil price environment assumed from the start of 2026, our modeling shows that leverage would only exceed 1.5x at the end of 2026 before declining again through 2027.

So in summary, our value creation plan is on track, and we have both the capacity and the resilience to fund our investments and deliver attractive shareholder distributions in the years ahead. And when it comes to shareholder distributions, we stick to our guiding principle that the dividend should be resilient and reflect our financial capacity through the cycle, taking into account both our long-term outlook and our credit profile. As we enter 2026 with a strong balance sheet, a high underlying cash generation from our producing assets, we have a solid foundation to stay true to our ambition of growing the dividend by at least 5% per year throughout this investment period to 2028. We are, therefore, proposing a 5% increase for 2026, which takes the total dividend to approximately $2.65 per share paid quarterly.

Now let me round off with a few comments on our 2026 guidance, starting with near-term tax payments. The tax payments in the first half of the year reflect taxes accrued in 2025. We expect tax payments around $300 million and $450 million in Q1 and Q2, respectively. For the second half of 2026, the tax payments will be set around midyear based on an updated full year estimate. In this chart, we illustrate what those payments may look like under different oil price scenarios. One clear takeaway is that with an oil price below $70 for the year, tax payments in the second half would be limited due to our investment program. This is a key feature of the Norwegian tax system. It provides resilience to market volatility when investing in profitable growth.

And finally, the guidance on other key metrics for 2026 is as follows: For 2026, we expect average production of 370,000 to 400,000 barrels per day. These estimates are based on P50 bottom-up assessments across our portfolio, and the range reflects the simulated uncertainty in those forecasts. The reduction from 2025 is driven by underlying decline in several fields, partly offset by start-ups of new subsea tiebacks in the Eiga and Skarv area. Operating expenses are expected around $8 per barrel produced. This is up from the 2025 average of $7.3 per barrel, driven by the weakening of the dollar against the Norwegian kroner and lower production year-over-year.

As already discussed, we estimate total CapEx for 2026 to come in between $6.2 billion and $6.7 billion, down from $7 billion in 2025. Abandonment expenditures are expected to be broadly in line with last year at around $100 million, with plugging and abandonment of old wells on Valhall as the main driver. Lastly, 2026 is set to be another active exploration year with 12 wells currently planned, including seismic and early phase maturation. We expect total exploration spend of around $400 million.

And with that, I'll hand it back to Karl for some final remarks before we move on to the Q&A session.

Thank you, David. Aker BP delivered a strong performance in the fourth quarter and throughout 2025, achieving low production cost, low emissions and production at the high end of our originally guided range. Our major projects progressed as planned and remain on schedule for start-up in 2027. The investment estimates have been increased for several reasons, not at least that additional barrels have been added to the projects. The ongoing tie-in projects have accelerated start-ups and all are now starting up in 2026.

2025 was an outstanding year for exploration as we participated in the 3 largest discoveries on the NCS and added around 100 million barrels of resources. We have a clear and well-defined plan to sustain production above 500,000 barrels per day from 2028 with even greater ambitions beyond that, amongst other, assisted by the increased volumes in the Yggdrasil area and the PWP-Fenris area. Aker BP acknowledges the new reality on the NCS. We are preparing for the future by rethinking how we mature and develop our discoveries faster, leaner and with far better insight. By working as one team across our internal functions and the broader ecosystem, we will deliver the next generation of projects in a significantly more efficient way. And we remain committed to delivering shareholder value, including a planned 5% increase in base dividends for 2026.

We will now take a short pause before opening the Q&A session. And to participate, please use the Teams link on the webcast page. And if you prefer to listen only, please stay tuned. We will resume in 1 minute.

[Break]

Welcome back, and I do apologize for the short break. But as usual in this business, we need to keep pace. And as also usual, our master of ceremony for the Q&A session will be Kjetil Bakken, our Head of IR, and I'll hand over to you, Kjetil.

Thank you, Karl. And let's cut to the chase. The first question today comes from Teodor Sveen-Nilsen from Sparebank 1 Markets.

Might be, but we hear nothing.

Sorry, Teodor, we have a small technical issue.

Okay, you can't hear us?

Now, we can hear you.

So I guess I'm limited to 2 questions, although Kjetil didn't say that, but I'll limit myself to 2 questions. First one, you showed this beautiful graph on production going forward, where you show flat production into the 2030s. Var Energi tells the same flat production and Equinor also tells that production will be flat until 2035, while the Norwegian Petroleum Directorate, they believe or the base case is substantial decline. So who is correct? If you just could shed some light on your thoughts there, that would be very useful. And also maybe how Wisting comes into play into the guidance of flat production going forward. So that's the first question.

Second question that is on dividends. You increased dividend by 5%, as you have indicated, as long as oil price stays above $40 per barrel. But how should we think about this after Yggdrasil first oil? Should we expect you to change that guidance or increase it? I assume that CapEx profile will look very different after Yggdrasil first oil. So that's my 2 questions.

Thanks, Teodor, and thank you for limiting yourself to 2 questions. Even though they were very fundamental questions, I'll try to be a little bit brief. There is no doubt if you look at the Norwegian Continental Shelf and, call it, the outline of the different companies and their inherent strategies as you just very succinctly presented that there will be a challenge on the Norwegian Continental Shelf. And this is the very precise background for the presentation that Marte gave a bit earlier today, our long-term focus on AI and time compression and how we think about alliance models to actually create a significantly more time-compressed field development.

Combine that with our efforts on exploration, not least the delivery we did last year with 100 million barrels, but also the APA awards this year, we have, over time, built a significant backlog, both of prospect leads, discoveries and very early phase projects. So my view on this is, yes, the overall Norwegian Continental Shelf is likely to decline over time. But I can assure you, we've been prepared for this for a long time, and we will do whatever it takes to lead that game.

And then I think there's a final point, Aker BP, because of a bit of a later startup of our projects, starting up in 2027, we actually have a little bit of a less challenge than some of the other companies that you referred to managing that decline into the 2030s. But it is a key point as we also highlighted in today's presentation, and there's a long list of measures being implemented by Aker BP as we speak, while we're executing the projects to mitigate that exact observation. Do you want to talk about dividends?

Yes, I can do that. So the current dividend policy is very clear. So our ambition is to grow the dividend by a minimum of 5% through this investment period. And that's also what's the basis for the dividend increase that we have indicated for 2026. When it comes to what happens after 2028, I think that, that's something that we will need to refer back to. But I think the key message from us is that we invest to create value, and all the value that we create will be returned back to shareholders over time.

And on the long-term production profile, I definitely agree that looking at history, probably the Offshore Directorate is too conservative. I'll leave at that.

Let's move on, Kjetil.

Yes. Next question today comes from Tianhong Bi from Citi.

Still can't hear Tianhong.

Tianhong, please give us a second. We have a technical issue again. Sorry for that. I think -- can we come back to you later on. We'll sort it out, Tianhong. We are not able to get your feed into the system here. We'll move on to James Carmichael then from Berenberg.

Can you hear me?

Yes, we can.

Just a couple, please. Just firstly on Wisting. I guess you sort of flagged it as an important project in the longer-term production profile. Just what's the situation? Any progress update there? And I guess, whether you've been able to utilize any of the AI that you've talked about in terms of accelerating that project or improving the economics.

And then just on the exploration campaign for the year, 12 wells, they all look to be in the North Sea, nothing in the Norwegian Sea or the Barents. I'm just wondering if that's a sign of things to come in the exploration strategy or just the way it's fallen this year?

Thank you, James. When it comes to Wisting, obviously, we are not the operator. So the way I see this is that the sea studies is starting. We will likely choose an engineering provider sometime mid-2026, and then a DG2 towards the back end of '26, and a DG3 towards the back end of '27. And then hopefully, an efficient execution model. And then I'll ask you to question the operator, whether they're implementing any of their artificial intelligence.

When it comes to exploration, this is a bit simpler actually. In 2026, we are spending most of our available rig days drilling the production wells that goes across the semi-subs and also the jack-ups. That means that we, from an operated perspective, have concentrated on the Utsira High area. So this is basically just an allocation of rig capacity in 2026. And then you might have noticed that we've actually contracted a new rig from 2027, the Noble GreatWhite to add in capacity to cater for the higher-than-expected wells to be drilled need. As you also saw in the presentation, we now have several IOR targets and new wells rolling into the portfolio as a result of the ongoing drilling campaign. So the 2026 campaign is simply an allocating of rig resources.

All right. Let's move on, or move back, as the case may be.

Yes. So next in line is Naish Cui from Barclays.

Can you hear me?

Absolutely.

Perfect. I have 2 questions, please. I thought it was really interesting to hear the digitalization and AI deployment at Aker BP as well as your alliance model, which is very differentiating. I wonder if you are able to quantify the impact of those on your financial performance such as production cost per barrel? I don't know, a lot of savings, perhaps in the long term, if you can quantify that, that will be good, or just give us a bit more color on that.

Then my second question is on your 2026 production guidance. I want to ask, let's say, if we exclude the acceleration of 2027 production that was brought forward to 2026, for example, the Skarv area, the Utsira High area, what would be the underlying production range?

Yes, you might have a think about the last question while I answer the first. So first of all, I think it's fundamentally important to understand this discussion around digitalization. And the way I usually describe it is that this is almost a continuous process. So you first optimize, call it, the analog work process. Then you digitalize it by implementation of tools and transforms and human machine interfaces and the whole stuff that we're used to in the retail space.

And then now we are taking the next step, and we're implementing artificial intelligence. But that is a completely different way of thinking about organization, processes, competence, needs, et cetera, et cetera. And as an example, what usually was a planning process for a maintenance operation or maintenance planning offshore would usually take about a week from start to finish. Now with Agentic AI and Agentic-powered tooling, we can actually do that in a matter of minutes, not in a matter of days. And we see the same thing in root cause analysis, what used to take weeks are now taking hours. So you're actually observing a collapse in work processes that we haven't really seen before. And we're able to do this because over time, we have invested in what was ultimately an AI-ready architecture where you can deploy these systems and agents on top.

And then this discussion around saving, I'm also having a little bit of a problem conceptually with that idea, because that takes as a starting point that you have some sort of fixed underlying performance and then you're measuring your performance against that underlying performance, which might be fine if you were improving analog processes or implementing digital tools on analog work processes. But what you're actually doing here is that you're fundamentally transforming the way an organization works. So there is really nothing to compare it against.

What you should be looking for is cutting-edge performance in terms of time to first oil. You should look at our ability to discover oil. You should look at our underlying performance in terms of uptime, plant efficiency, maintenance efficiency, et cetera, et cetera. It will take a bit of time before that works itself into the financials. But I think that is the ultimate proof point. I really struggle with this idea and companies coming out and saying they've saved X, Y and Z by implementing this and that. I really don't understand how that is a measurable quantity.

You want to talk a little bit about production guidance?

Yes. So I guess your question is, to a large extent, what is the incremental impact of accelerating the Skarv Satellites into 2026 versus the original plan, which was in the start of '27. And we typically don't like to give sort of detailed guidance on a field-by-field basis. But to give you an idea, this is probably in the range of 1% to 2% of production. So we're talking about maybe 5 to 6 barrels per day (sic) [ 5,000 to 6,000 barrels per day ] of impact from that. So it's not material in the bigger sense of the portfolio, but of course, very important in terms of how we are executing the projects.

And very important for the Skarv asset.

And very important for the Skarv asset indeed. That's true.

Let's move on, Kjetil.

Yes. Then next caller is Victoria McCulloch from RBC.

Can you hear me okay?

Yes, we can.

So just some questions on CapEx in particular. Can you give us some color on how much of the Valhall CapEx increase was spent in 2025? Then looking at '25 and '26, do these CapEx budgets include incentive mechanism payments that I guess we've seen in the past for your alliance partners? And then on 2027, you mentioned that there's been an increase from 12 months ago. Can you give us maybe a bit of magnitude on that? And how much of it's been Valhall and how much of it is keeping to the schedule that's driven up the OpEx?

Yes, you want to talk about the 2027, and I'll do the '26, '27?

Yes. '25, you mean?

'25, I mean.

'25, yes, I can do that. So we have quantified that to roughly $200 million in '25, which is linked to Valhall. And then the other, call it, deviations in '25 is currency effects and some other deviations.

And then for '26 and moving forward, when it comes to Valhall specifically, about 1/3 of the increase is related to one new production well at Fenris following excellent results of the Fenris drilling campaign, 4 new wells in the Valhall area following better-than-expected performance on the already drilled Valhall wells, and the remaining part of that is related to essentially an up-manning at the Stord yard following a period with a little bit less productivity than we assumed, simply to make sure that we are resourcing it to guarantee that we're delivering on time. And then this estimate includes all the total costs that will be incurred by Aker BP, whether that is a direct payment or it's fees or bonuses or other payments.

All right. Next question comes from Chris Wheaton from Stifel.

Two questions, if I may. Firstly, CapEx, not so much the impact on '25, '26, but I'm interested, longer term, do you think you've moved up from that sort of $15 a barrel of incremental CapEx spend to hold that production at above 500,000 a day. And I'm interested how much do you think, if so, that has gone up? How much that has increased?

Secondly, a question on reserves. Total 2P plus 2C end of '25 was up only 20 million barrels versus end of '24, and that's despite the excellent exploration success you've had this year. I wondered then if those barrels from this year's exploration success are actually going to come into the reserves numbers next year instead, because I was surprised there was such a small increase in those numbers. That will do for now.

So the first one is the easiest to answer. The answer is yes. You're a bit ahead. So most of this will come into the resource and reserves reporting on the year following the discovery. So that is correct. And then on CapEx...

I can cover that.

Yes.

So what we have said in the past, Chris, is that we expect a range between $15 to $25 per barrel going forward. And then we have said that when you invest in new facilities to create, call it, facilities to also cater for area developments, new tiebacks and so on, you could put in place infrastructure, which drives up the, call it, starting point on the cost per barrel in the higher end of the range, while when you're drilling infill wells or doing subsea tiebacks, that number should typically be lower.

And then you can see that, for example, from the wells that we now added in the PWP-Fenris project, the 5 wells there. And when you look at the number of resources we're adding, the cost per barrel goes down quite significantly, right, because you've already pre-invested in the facilities. So there will be a range. And there's nothing that's happened since we discussed this last time, which indicates that, that number is increasing significantly.

Quite the opposite.

Quite the opposite, as Karl is saying here. I think that the efforts that we are doing across the board, as also talked about in the presentation today, should indicate that we will be able to bring that down going forward.

That would be really interesting if you could -- I mean, it'd be amazing if you could do that, but keep up the good work.

All right. Tianhong Bi, we are having some trouble with connecting his sound. So he has sent us the questions on e-mail, so I'll read them out.

Okay. By Proxy, that's great.

From Tianhong Bi of Citi. Good to see some update on the Sverdrup redetermination process. We've seen a very wide range of possible outcomes on the NCS recently. With the results just a few months away, are you able to shed any light on what we should expect at this stage of the process?

And please just remind us, if the outcome is favorable for you, would that trigger any cash reimbursements this year? Or is everything settled through future production? And does the upper end of your CapEx guidance include any contingency for a potential reallocation? It is interesting to see you have been awarded for several tight gas reservoirs in the latest APA round. Those historically have been viewed as uncommercial. Given your portfolio is quite oil-weighted and you've typically prioritized higher return, low breakeven projects, this looks like an unusual move. What's driving your interest in tight gas now?

Excellent questions, and well presented. Thank you, Tianhong. On Sverdrup, I think you should -- I think I'll refrain from commenting both on process. But I can say that any changes to tract participation in Johan Sverdrup is not accounted for in our 2026 forecast, whether that is on the production or on the CapEx side. And then if there is attract participation change, that means that if it's positive to us, that means that the production will go up slightly. We haven't accounted for that, but CapEx will also go up slightly. And there are a 2-year kind of restatement process for '26 and '27. So neither is accounted for in our guidance for 2026.

And then on process, I think I'll leave that to the operator to comment on. On tight gas/tight oil, I think it's important to note that we've actually been a very active operator of tight oil for a long time in Aker BP. Valhall field is essentially a tight oil play, and we have been probably the most active, call it, deployer of fracking technology and other stimulation technologies against a tight oil play. So we have, for quite some time, spent a bit of time and resources understanding the tight oil.

And then your question, why, and I understand that you might believe this is an important move. Well, I'll go back to where Teodor started this morning, pointing out the challenges on the Norwegian Continental Shelf keeping the reserve number up. If you look at the total amount of discovered but undeveloped resources, tight oil, tight gas constitute by far the largest portion. So for us, focusing on the Norwegian Continental Shelf and building on years of experience with tight oil and tight gas and the fact that we are now essentially outdrilling the other operators on the Norwegian Continental Shelf, and drilling is such an important part of the cost in tight oil and tight gas, it was actually a natural move for us to now go after these resources. So that means that we have picked up, as you correctly point out, quite a number of licenses, and we're progressing technology projects and development projects in parallel. We do believe that this will be highly value-accretive barrels on the Norwegian Continental Shelf with a significant volume potential.

All right. Thank you, on behalf of Tianhong. And then the next question comes from Mark Wilson from Jefferies.

Can you hear me?

Yes, we can.

I can't hear you anymore. But I'll ask my question anyway. I have to ask on Johan Sverdrup and the production guide outlook. There seems to have been a race to the bottom in terms of exploration expectations into this event, but I hear or see nothing new. We've been here before, 2 years ago, water breakthrough expectations that was managed incredibly well. The field was expected to come off plateau in late 2025, here we are in '26. What are the variables in your guidance this year and beyond that with the drilling and field management options that you have?

Thanks, Mark. I certainly buy into your statement that this is actually nothing new. What we're seeing now is pretty spot on what we have in our models and our projections going forward and what we have had going into 2026. The variables here are, as almost any other field, I would say, essentially trying to stop the decline by drilling new wells or implementing well changes for us. There are new wells being drilled at the DP. There's a retrofit multilateral campaign, which we've now been in the middle of, and one well has started up and another well is coming. And then you have the Johan Sverdrup Phase 3 project coming on stream in 2027. So that's basically what we would, in any other field, call an IOR campaign and should be considered the same here, and there will be more.

And then it's all about how we actually run production. It's about the balance of mass outtake, volume injection through the water injection system, and then understanding how the coning and the coning behavior of these wells behave. And again, and I've said this several times in this presentation, here I say Statoil is doing an excellent job and have been doing an excellent job mitigating and fighting the decline. I see no new information. And I still believe that Johan Sverdrup is a fantastic field that will continue to outperform.

I think we lost Mark. So let's move on.

Mark froze, but hopefully, he got the message. Okay. We'll move on to the next caller. John Olaisen from ABG.

Yes. I have to test this mic, but can you hear me?

Absolutely.

Fantastic. That's great. Two questions on exploration. First, I noticed that you're drilling an exploration well in the Johan Sverdrup area, the Tonjer now in Q1. I just wonder -- a bit curious actually, it looks like it's relatively small potential for that well. But I just wonder, is this a small pocket you're drilling? Or is it testing for a potential new play opener, so to speak, for the area? And also, if it turns out to be a discovery, is this something that could be tied in and start production fairly soon? So that's the first question on the Tonjer exploration well.

And secondly, more in general, you're using a lot of AI, as you say, on exploration. I just wonder the implications -- are the implications that you will need more seismic data, but we'll be able to drill fewer exploration wells? And then the second part of that question is, do you expect to increase exploration success rates going forward? Maybe also comment a little bit on potential difference in commercial success versus technical success. As you know, in Norway, there's been a lot of technical success, there's fewer commercial successes. So if you could elaborate on a little bit of that as well, please.

Sure. Absolutely. Thank you, John. Tonjer, Tonjer is essentially the northernmost extension of the Johan Sverdrup field with a possibility of a difference in oil quality, oil-water contact, et cetera, et cetera. So that's why we're drilling an exploration well. No, it's not -- I would really wish it to be a play opener, but I don't consider it a play opener. I consider this more almost like an appraisal well to understand whether there is a basis for a subsea tieback from the Tonjer area back to the Johan Sverdrup field. And then I do sincerely hope and would urge the operator, if we do make a discovery, to expedite the tieback of Tonjer to the host.

And then on AI, I don't think it will change the way we consume seismic in terms of volume. I think it's -- a better way of looking at it is, it's almost like a digital laboratory, right, where you can test concepts, you can dig into data, you can actually play with concept and then hold that up against the database that you have in a consistent manner. You could always do stuff like automatic seismic interpretation and data analysis. And, of course, machine learning algorithms driven by AI agents is kind of revolutionizing the pace we are retransforming this data to test different hypothesis.

But I don't really see that there's a fundamental change in our consumption of data, maybe with one exception, and that's the move from towed streamer seismic to ocean bottom nodal seismic, simply because these algorithms are now using not only the pressure wave, but also the shear wave to optimize what they basically call the way of differentiating between rock and the fluids in the rock.

And yes, of course, it is for us about increasing the chance of success. It's about avoiding drilling wells where we can see that there has been a bias by the people involved. I mean, we all get to fall in love with our concepts, and I do that all the time. Fortunately, I have David, which is helping me break out of those love relationships for most of the time. But it is about actually understanding what are the real data and what is the bias data. It is about testing more plays. So it's also about acceleration and processing of more data on the Norwegian Continental Shelf. And yes, we are, in fact, kind of digitally drilling exploration wells into these models and testing the data before we actually do drill. So over time, I expect also a higher chance of success. And where the wells we actually do drill are much better based on the data that exists.

And then there are areas on the Norwegian Continental Shelf, you could call it the high potential areas, where there is actually little data. And it is a fact that AI actually only works if you have sufficient amount of data to educate the algorithm. So there will be a kind of a balance between humans and the AI interacting with the data. So it's a little bit of a mixed picture, but it is certainly a lot of promise in the way we are now deploying artificial intelligence in the subsurface disciplines.

Do you think you'll reap the benefits of that already in 2026? Or is it still a little bit further ahead?

I think it's fair to say that we've already seen the benefits, John. So the stuff that we did on Omega Alfa with the directional drilling at ultra-high speed is, in fact, the deployment of several technologies that are basically being deployed in one well. A few of the other wells we drilled in 2026 were also supported. And the APA application that we just were awarded was, to a large extent, fueled by a series of artificial intelligence agents even down to actually writing most of the application. So it is not something that is coming in the future. It's something we're actually working active in the current business today.

Yes, then we have time for 1 follow-up question from Teodor Sveen-Nilsen, and this will be the last question today.

It's actually a follow-up on one of my questions. And that is a discussion -- this could be a long answer, but it's the discussion between buybacks and dividends. Why don't you buy back shares? You will probably answer that it's too low free float, but Equinor, they are buying back shares and they're certainly low free float than you have.

Thank you, Teodor. I think you promised only 2 questions, but we'll certainly be happy to answer. David will be happy to answer your question #3.

Yes, I can do that. So I guess we've had that discussion in the past, and I think there's difference in opinions around how you distribute value back to shareholders in the most efficient way. I think based on our business, our investor base, we have concluded that distributing it through dividends is the most efficient way. And then we have said many times that buybacks is also part of the toolkit. So I won't exclude it in the future, but currently, the policy is that dividends is the main way of distributing and the ambition stands as said earlier today.

And then Kjetil, we'll close for today.

Yes.

So thank you to everybody for listening in. Thanks to everybody who have asked questions. And then I wish you a great day, a fantastic week, and whatever you're doing. As I usually say in closing on my town halls, stay safe.

Good morning, and welcome to Aker BP's presentation of our third quarter 2025 results. Today's agenda reflects a strong quarter with clear momentum in both operations and strategy. We'll start with an update on the operational performance, which continues to deliver solid results. Then we'll move to our field development portfolio, where we remain firmly on track. We're also very pleased with our exploration results. So far this year, we've made 2 significant discoveries, Omega Alfa and Kjøttkake. And with several additional wells currently being drilled, we see the potential to reach 100 million barrels discovered in 2025, net to Aker BP. And as always, CFO, David Tonne, will take us through the financials later in the presentation.

In the third quarter, production averaged 414,000 barrels per day, in line with previous quarters. This time, we had a planned maintenance shutdown at Grieg Aasen, similar in impact to the maintenance shutdown at Valhall and Ula in Q2. Despite the shutdown, portfolio-wide production efficiencies stayed high at 96%. Other assets, including Johan Sverdrup continued to perform very well with efficiencies ranging from 92% to nearly a perfect 100%. Looking ahead, we expect our assets to maintain strong performance even as natural decline offset some of that strength. Based on the strong year-to-date production and updated forecast for the remainder of 2025, we are raising our full year production guidance to 410,000 to 425,000 barrels per day.

Now let's have a quick look at our cost performance. Reported unit cost edged up to roughly $7.6 per barrel this quarter. But as David will come back to, the underlying unit cost was essentially unchanged from the previous quarter. And we remain firmly on track to deliver on our full year guidance of $7 per barrel, a level that is highly competitive in the industry and underscores the strength of our assets and operations.

On CO2 emissions, the picture remained consistent. Our emission intensity held steady at 2.9 kilograms per barrel as it's been throughout the year. This is an industry-leading level that continues to set the benchmark. Simply put, we are the global leader in low emissions oil and gas production. Earlier this year, we outlined our ambition to sustain production above 500,000 barrels per day beyond 2030, and to pursue further growth. And I can assure you, we work every day to make this a reality. On this illustration, the dark blue area shows the current business plan, that is production from existing fields, ongoing field developments and regular IOR activities.

Key growth drivers include the large-scale Yggdrasil development, which contains now the East Frigg discovery, the Valhall PWP-Fenris project, and a series of tiebacks to Alvheim, Skarv, Grieg Aasen in addition to Johan Sverdrup Phase 3. This outlook supports our target to produce around 525,000 barrels per day by 2028. Beyond 2028, the light blue wedges illustrate our potential to sustain production over 500,000 barrels per day for infill drilling and tieback from known discoveries across the portfolio. Progress this year, especially our exploration success, strengthened my confidence in this trajectory.

Now looking further ahead, we see significant growth potential beyond our current outlook. Continued exploration success and targeted M&A provide a clear path to expand our production base well into the next decade. A recent example is our increased ownership in the Kjøttkake discovery, where the partnership is already actively evaluating possible development scenarios.

So in total, this is our ambition, and we are well equipped to deliver it. We have the people, the assets, the supplier, the digital ecosystem, the capital, the track record and the project to make it happen.

[Presentation]

Impressive work by the subsea alliance indeed. The launch of the Yggdrasil bundle is spectacular, and it's now been safely installed at the field. And as we heard in the video, because we all do all commissioning work before sail away, it is truly the fastest way of developing a field. Our projects continue to advance steadily with several key milestones achieved in the recent months. These include the successful offshore installation of 4 out of 5 jackets at Yggdrasil and Valhall PWP-Fenris, installation of subsea templates and the completion of the Fenris drilling campaign.

These achievements reflect the scale, pace and precision of our execution. They are the results of close collaboration across teams and partners, and they mark critical steps towards delivering on our long-term value creation. We are now at the midway point of our execution phase with engineering and procurement nearly complete. We're also at the peak construction, and we have reached a point where modules are being assembled into complete platform units. This gives us clear operational visibility into the remaining work and resource needs. For the projects, they remain on schedule for planned start-ups in 2026 and 2027.

Let me now turn to exploration. When we last met in July, we had drilled the first sections of the Omega Alfa well, which confirmed commercial oil volumes in the range of 20 million to 40 million barrels at that point in time. Now over the summer, we completed this exploration campaign. The result was a significant oil discovery that adds substantial new resources to the Yggdrasil area. The recoverable volume is estimated at 96 million to 134 million barrels of oil equivalents. It is among the largest commercial discoveries in Norway in a decade.

Building on the momentum from the oil discovery at East Frigg in 2023, this marks a major step towards our ambition of producing more than 1 billion barrels from the Yggdrasil area. The success is also a result of strong calibration between our own teams and our alliance partners and a testament to how new exploration methods push the boundaries. And luckily for us, we equipped the team behind the discovery with a camera during the operation. Here is their report.

[Presentation]

Thank you, Aasmund, Torstein, Hanna and the rest of the team for the great work. And yes, Hanna, I agree, this is only the beginning. Omega Alfa is not just a big discovery. It represents a step change in how we explore. The methods proven here will shape the next chapter of exploration in the Frigg area and beyond. And why does that matter? Because it gives us speed, precision and confidence. It means in reality that we can shorten the time from discovery to development and thereby unlock value faster.

Frigg was once a giant gas field, decommissioned after producing 700 million barrels oil equivalents of gas. Today, with new insight and new technology, we see significant oil potential in the same area. This is a major upside for Yggdrasil and for Aker BP's long-term growth. Our exploration team has also delivered other strong results this year. In the first quarter, we made a promising oil and gas discovery in the Kjøttkake in the Northern North Sea. The reservoir shows good quality and estimated gross recovery volumes stand at around 50 million barrels. Located near existing infrastructure in the Troll-Gjøa area, this is clearly a commercial discovery. And we have, after the discovery, increased our ownership in the license to 45% from 30%.

The partnership is already evaluating development solutions. Together with Omega Alfa and the smaller E-prospect at Skarv, we have added approximately 75 million barrels net to our resource base from exploration in 2025. And the year is not over. We are currently drilling several exploration wells, including Natrudstilen in the Yggdrasil area and the Equinor operated Lofn and & Langemann west of Utsira High. With the risk potential in the remaining wells, total net discoveries could reach 100 million barrels before year-end. And in that case, making 2025 our most prolific exploration year since the Johan Sverdrup discovery in 2010.

Good morning. As Karl highlighted, we delivered another solid quarter with strong operating cash flow driven by stable production, high efficiency and good cost control. We also maintained good progress and remain on track with our development projects. In addition, we significantly strengthened our resource base through the Omega Alfa discovery and by increasing our interest in Kjøttkake. At quarter end, our financial position remains strong with ample liquidity and low leverage. This allows us to navigate market volatility while executing our investment program and maintaining a resilient dividend to shareholders. Altogether, this quarter marks another step forward on our value creation plan.

Let's now take a closer look at the main drivers behind the results. Net production was on par with the previous quarter, impacted by a planned shutdown at Grieg Aasen for maintenance. Production in Q3 was 414,000 barrels of oil equivalents per day and underlift brought sold volumes down to 396,000. Operating costs increased to $7.6 per barrel, slightly up from the last quarter due to the production mix and some one-off infrastructure costs. Year-to-date, the unit cost is $7.1, and we are on track to deliver on our full year guidance of around $7. Cash flow from operations reached $2 billion in the quarter. The main drivers were good operational performance, low tax payments and stable working capital. Investments were in line with the second quarter at $1.9 billion, reflecting high activity across our project portfolio and a slight weakening of the U.S. dollar since the first quarter. Within financing cash flow, the main item was the dividend payment of $0.63 per share in the quarter.

Zooming in on a few items in the income statement. With slightly lower sales volumes, but marginally higher realized prices, revenues were stable compared to the second quarter at around $2.6 billion. As mentioned, the cost per barrel produced increased a bit, but total production costs in the P&L were actually down due to the underlift.

Net financial items were impacted by currency losses from a weaker U.S. dollar. But on the positive side, our NOK hedging program, which covers current tax liabilities and investment plans generated $11 million this quarter. Impairments totaled $173 million related to technical goodwill on Johan Sverdrup and Valhall.

The main driver is that we produce from assets where technical goodwill has been allocated in previous M&A transactions. And since technical goodwill is not depreciated under IFRS, we must impair goodwill as we produce from the assets, all other things equal. Since goodwill impairment has no tax impact, this leads to a high reported tax rate of 80%. Adjusted for impairments, earnings per share was $0.73 in the quarter, and the effective tax rate was 71%. For more information on technical goodwill and impairments, I recommend, as usual, watching the explanatory video that we have published on our IR website.

Now let me also briefly comment on cash flows. The third quarter marked the start of the new tax payment process for E&P companies in Norway. Tax for the year is now paid in 10 monthly installments with a final settlement in the fourth quarter of the following year. The first payment is in August with no payments in January or July. So with only 2 installments this quarter and investments at peak level, taxes paid were relatively low at around $300 million. As mentioned, cash flow from operations then ended at $2 billion in the quarter, and then free cash flow was around $0.24 per share.

Turning to the balance sheet and liquidity. With strong operational performance flowing through to the financials, we exit the third quarter with a solid financial position. As shown in the chart to the left, net interest-bearing debt increased to $5 billion. At the same time, tax payables decreased from almost $1.8 billion to $1.6 billion. Our leverage ratio remains low, but as expected, ticked up slightly to 0.5x net debt/EBITDAX. Total available liquidity stands at $5.6 billion, providing ample flexibility. The quarter-on-quarter decrease reflects $400 million lower cash and cash equivalents, of which almost $200 million was used to reduce tax payables, as mentioned.

We have also progressed the refinancing of our existing $3 billion revolving credit facility, which was set to mature next year. Last week, we secured commitments from a bank syndicate to establish a new facility of minimum $3 billion. This is split into a liquidity facility of $2 billion with a 5-year tenor, including extension options that could take maturity out to 2032, and a working capital facility of minimum $1 billion with a 3-year tenor and an option to extend maturity to 2029. A strong balance sheet with financial flexibility remains important as we move into the final stretch of 2025, and we are now halfway into our 2023 to 2028 value creation plan.

Earlier this year, we completed a comprehensive project review where we also updated the investment estimates for 2025 to 2028. This was reported at our second quarter presentation, and these estimates, as shown on this slide, remain firm. We continue to expect 2025 to be the peak investment year with capital expenditures reaching around $6.5 billion before tapering off from 2026 and onwards.

As more than half of our investments are denominated in Norwegian kroner, our estimates in U.S. dollars are sensitive to FX fluctuations. Over the last 4 years, we have benefited from a weakening of the Norwegian kroner versus the U.S. dollar. And to lock in some of that benefit and to mitigate the financial exposure to a potential strengthening of the Norwegian kroner, we have hedged between 75% and 90% of our planned Norwegian kroner expenditures in 2025 to 2027 at an average USD-NOK rate between NOK 10.5 and NOK 11. The financial effects of this FX hedging will not impact reported CapEx. They are recognized on another line in the financial accounts.

As shown in the notes to the balance sheet, our FX derivatives positions are valued at approximately $150 million. 90% of this relates to hedging of our planned NOK expenditures and the rest relates to tax payables. With a 22% tax rate on FX derivatives, the after-tax value of our spend-related hedges is $107 million. And just for comparison, this corresponds to over $800 million in pretax CapEx under the 2020 tax system, which applies to most of our investments.

As mentioned, we are now halfway into our 2023 to 2028 value creation plan. By the end of 2028, we estimate to have generated between $9 billion and $13.5 billion in cumulative free cash flow, depending, of course, on how oil and gas prices develop over the period. In turbulent and volatile times, resilience matters, and we have built the financial resilience to withstand oil price volatility. Consequently, our financial metrics remain robust across most plausible oil price scenarios.

Assuming a continued 5% annual increase in dividends, our leverage ratio remains comfortably below the internal threshold of 1.5x and well within the bank covenant limit of 3.5x. And even in a prolonged $50 oil price environment, conservatively assumed from the beginning of 2025, our modeling indicates that leverage only temporarily exceeds 1.5x in 2026 before declining again in 2027. And given that our average realized oil price is around $70 per barrel for the first 3 quarters and approximately 40% of our estimated oil exposure for the fourth quarter is hedged at $65 per barrel, this downside case is conservative. In summary, our value creation plan is on track, and we have the capacity and resilience to fund investments and deliver attractive shareholder distributions in the years to come.

Then turning quickly to shareholder distributions. Our guiding principle is to maintain a resilient dividend that reflects our financial strength and outlook. Our ambition to grow the dividend by at least 5% annually through this investment cycle remains firm. And for 2025, we are delivering on that commitment with a total dividend of $2.52 per share. We have already paid 3 of the 4 quarterly installments, and the Board of Directors has resolved to pay the fourth installment of $0.63 in early November.

Let me round off with a review of our guidance for 2025. Production averaged 423,000 barrels per day in the first 9 months, above the top end of our full year range and slightly above our expectations. We still expect some natural decline and minor planned maintenance in the fourth quarter. But with 3 quarters behind us, we are raising the full year estimate range to 410,000 to 425,000 barrels per day. Production cost is $7.1 per barrel year-to-date. And although the recent strengthening of the Norwegian kroner adds some risk to the full year estimate, we maintain strong cost control and still expect to end the year at approximately $7 per barrel.

Investment activity remains at peak levels with construction and drilling operations running at full speed. We've invested $4.9 billion year-to-date and maintain our full year guidance at approximately $6.5 billion. The year-end outcome will depend on progress, phasing effects and currency levels. And again, note that benefits of FX hedging do not reduce reported CapEx, but are recognized elsewhere in the accounts.

Exploration results have been strong in 2025. We now expect to drill 18 wells in total, and the full year estimate has been raised to around $500 million pretax, driven by the high activity level and the extended scope of the discovery wells. Abandonment activity are also on track. We revised the estimates down in the second quarter to around $100 million, and we now expect to end slightly below that level.

And with that, I'll hand it back to Karl for some concluding remarks.

Thank you, David. And while I do appreciate that David's presentation might be the highlight for some of you, let me wrap up with a few key messages before we move to Q&A. We have delivered a solid third quarter operationally, strategically and financially. Production was stable at 414,000 barrels per day. Costs remain competitive and our emissions intensity is at industry-leading levels of 2.9 kilograms per barrel.

Based on our strong performance so far this year, we are raising our full year production guidance to 410,000 to 425,000 barrels per day. We are executing on our strategy, and we continue to invest in safe and efficient operations, digital transformation and low emission solutions. Our major projects are on schedule, supporting our goal to reach production above 500,000 barrels per day in 2028 and to sustain that level well into the 2030s.

Discoveries like Omega Alfa and Kjøttkake are clear examples of how we are building a resource base that underpins our long-term production profile. Our robust financial position and resilient cash flow enable us to deliver attractive, reliable dividends even as we continue to invest in profitable growth.

We will now take a short pause before opening the Q&A session.

So welcome back, and we will, as announced, now do the Q&A. And as usual, Kjetil Bakken, our IR champion, I would say, AI champion actually, will serve as our quizmaster also during this Q&A round. So I'll hand over to you, Kjetil.

Thank you, Karl. We will go straight to the first question, which comes from Tianhong Bi from Citi.

I've got 2 questions, please, if I may. The first one is on production cost guidance. Based on the midpoint of your new production guidance, volumes in fourth quarter looks to come in around 400,000 barrels per day, and that's 3% below this quarter. And linked to that with the year-to-date average at $7.1 per barrel, I think you need roughly $6.6 per barrel in fourth quarter to hit your $7 target for the full year, and that's 13% down from this quarter. That feels quite tight and doesn't quite add up given the lower production and you just talked about the Norwegian kroner strength adding some extra risk. So I'm just wondering what's driving that step down and where you're seeing the main cost reduction coming from?

And the second question is on Omega Alfa and the broader exploration potential around Yggdrasil. Should we think about these discoveries being developed as a series of subsea tiebacks to Hugin A? And assuming those FIDs come after Yggdrasil is on stream, we're essentially talking about incremental volumes coming a bit later, say, around 2030 rather than immediately extending the 2028 production peak. If you could just confirm that, please.

Okay. Production cost, David, do you want to talk about that?

I can do that. So the guidance for the full year is approximately $7 per barrel. And as mentioned in my presentation, we had some one-off costs related to infrastructure in the third quarter. So when we look at the best estimate that we have for the fourth quarter, we expect to end up roughly at $7 per barrel for the full year. So there's no magic to it. It's just underlying costs are stable, and we have had maintenance on a few assets over the past 2 quarters, and now we're back to sort of more stable production in the fourth quarter.

Thank you. Then turning to Omega Alfa and development concepts. It's, of course, quite early. So I would say there are 2 possibilities here, depending on what the final 1 or 2 exploration wells in the area will show. You can either have a series of subsea tiebacks or you will have some sort of unmanned installation in the area, trying to capture all of the volume to the west of the Yggdrasil area. Regardless of how these solutions will be developed, this will be a plateau extender on the current Yggdrasil plateau simply because with the current volumes and the inclusion of East Frigg, we don't have processing capacity at Hugin A to take in more volumes. So, in that case, you can see this as a plateau extend on the Yggdrasil plateau and, of course, then coming on the back of the curve that you saw on this strategy slide. So it's adding volumes to the curve, and it's reinforcing the message of 500,000 barrels well into the 2030s.

The next question comes from Anders Rosenlund from SEB.

Could you talk a bit about commodity hedging? You have a comment in the report indicating 40% oil price exposure covered for fourth quarter, but how is your exposure for the first quarter and maybe for the first half of 2026? And what's really the purpose of hedging at $65?

Excellent, Anders. I think this is your domain again, David.

Yes, I can do that. You're correct, Anders. So we currently have 40% of our oil price exposure hedged at $65 using put option. When it comes to 2026, we don't have any commodity hedges in place. Our strategy is to be opportunistic. And when we see that the cost benefit of putting in place hedges to both protect downside risk, but also lock in value, we do that. So that's the current positions and how we think about it also going forward into 2026.

Next question is from Teodor Sveen-Nilsen from Sparebank 1 Markets.

A couple of questions from me. First, on the exploration. You talked a lot about the strong exploration results this far in the year, which obviously is impressive. I was just wondering, looking into next year, is it tempting to increase the exploration activities and also increase exploration spending?

Second question that is on Yggdrasil. And last quarter, we talked a lot about the increased cost on Yggdrasil. And you say that the project remains on schedule, but also we see that increased costs also impact schedule. So I just want to know, have you seen any changes to schedule in some parts of the Yggdrasil project at all? Or is it only costs that you have seen increasing or changing compared to the PDO?

Excellent. Thank you, Teodor. So when we talk about exploration, we've been rather active on the upper rounds or the annual acquisition rounds of licenses on the Norwegian Continental Shelf in the last 4 years, where the overarching objective has been to build a portfolio of interesting exploration possibilities, prospects and targets in areas where we feel that we could actually aggregate volumes sufficient to make interesting field developments. I think this is now starting to play out. The Omega Alfa story is certainly a part of it with East Frigg and now Omega Alfa and follow-up wells coming in '26 and '27. But there will also be other prospects. So for us, it's a long-term strategy.

Then the other part of the same strategy is to maximize the volumes that we can create based on the number of dollars we spend on exploration. So at this point in time, there is no -- we don't intend to increase the exploration spend, but we intend to prioritize harder on the targets that we do drill in order to increase the yield of those exploration spends. We don't really see the exploration spend as a limiting factor at this point in time, to be quite frank.

Then on Yggdrasil cost. I mean, the cost increase that we talked about in Q2, and I don't think we talked about it a lot, but we discussed in Q2, was mainly related to changes in FX additions of the East Frigg into Yggdrasil and then some added resources that was necessary to drive the different acquisitions of parts and procurement elements in essence. And then, of course, some additional transportation costs, et cetera, et cetera. So the answer is very simple. We are on schedule when it comes to the Yggdrasil development. We have met all the milestones necessary in the quarter, and there is no slippage on schedule. So this is not your classical time-related cost. This is about us deploying capital to minimize risk.

All right. Then the next question is from John Olaisen from ABG.

I love the videos of the Yggdrasil-related work and also the detailed comments on the progress. However, from the outside, it's difficult to assess the progress when we do not know the milestones that we should expect. So I wonder if it's possible to give us some milestones of what we should look out for going forward. For instance, like key sailaway dates for the last jacket and the top sides. What kind of subsea work should we be looking for you to report that this is installed and the drilling progress, for instance. So some milestones to look out for, for the Yggdrasil development would be fantastic.

Yes. Thank you, John. So quite a few of those milestones that you actually report has actually been achieved. So we have installed all the subsea templates that is necessary. We are actually in the progress of drilling first the top holes and then the transport sections down to the reservoir as we speak. As you point out, we have installed the Munin jacket and the Hugin A jacket. The Hugin B jacket will be installed next summer. And the key sailaway dates will also be next summer where both Munin, Hugin A and Hugin B will be transported from shore and installed on the field. And then, of course, the last milestone and the most important milestone of all will be the start-up of Hugin in the first half of 2027. So this is why I'm saying that we're well into the execution program.

And is it possible to give some more dates on kind of the key sailaway dates? I presume the jacket is going to be earlier than the top side. Makes sense to check it first, I guess.

If it comes from The Economist. If we installed the Hugin B at top side before the jacket, somebody has made an error. That's correct. I don't want to give dates at this point in time because we are in the process of finalizing the installing program. This is always a discussion between us and the T&I contractor. In this case, it's both Allseas with the Pioneering Spirit and Heerema. And we are in the process of closing those windows. So the normal way of doing this is you enter into a discussion where you reserve slots on a schedule. And then in January, possibly February, we will try to lock down those slots to make sure that we have a very firm date.

And the next question comes from Naisheng Cui from Barclays.

I've got 2 questions.

He's got 2 questions. Are you ready?

Absolutely. We can hear you well.

Yes. I'm ready. Yes, I have 2 questions.

Always has 2 questions. The next guy, you're still...

Can you guys hear me?

There was some noise on the line.

There was some noise, but now I think we're clear. Go ahead, Nash.

Yes, I think someone else opened his line. Yes. I also have 2 questions, if that's okay. So yes, the first one is on your production guidance. You had a very strong operational quarter, Q3. You increased your production guidance twice in the year. Shall we think your new guidance is quite conservative as well? Will we be able to see any upside potential over there?

Then my second question, probably for modeling purpose, how should we think about impairment into Q4? Because I noticed we had quite a bit of impairment in the last 2 quarters. Do you expect more over there for the next quarter? Can you provide a bit of color there?

Excellent. And one, you're absolutely right. We have now increased the production guidance slightly over 2 quarters. We previously discussed this in one of these quarterly earnings calls where I've been very frank saying that what we put in, in our production guidance is what we expect as a P50 number. So the fact that we have slightly increased our guidance now first in the second half and now in the third quarter means that we are performing slightly better than our own P50 guidance.

What you should expect is that we also follow this P50 rule when we now update the guidance. So we are trying to be as transparent as we possibly can in the market, and wouldn't be a bad assumption to assume that the midpoint is quite close to our existing P50. And from that, you can easily deduct the expected production in Q4.

Then on impairment, David, this is your favorite topic in addition to tax, isn't it?

Yes, indeed, indeed. So quick on impairments, right? So I'm sure everybody is aware now that we do have quite a lot of information on our investor web pages with regards to what technical goodwill is and how you should think about the impairment related to technical goodwill. And in this quarter, we also had impairments of technical goodwill. Technical goodwill has arisen on the balance sheet through the acquisitions that we have done previously, and it's allocated to the various assets that we have acquired.

What you should expect is that we will have impairments of technical goodwill, all things equal, as we produce volumes out of the assets that have technical goodwill allocated. And the reason for this is that we are not able to depreciate technical goodwill. So we test every quarter to see if there is a need to impair it. And the variables, of course, are the underlying business. it's the, call it, assumptions related to commodity price and FX and actually also the forward curves and then, of course, the production from the fields. So all things equal, you should expect impairments. And then if there is significant changes in the forward curves of commodity prices, that, of course, has an additional impact.

Next one is Victoria McCulloch from RBC.

Firstly, on Omega Alfa, you highlight, again, the use of high-speed horizontal drilling. In the current, I guess, the list of wells you gave for the remainder of this year and into '26, are any other wells using this method?

And then looking at Grieg Aasen area, firstly, you did IOR drilling at Edvard Grieg this quarter, I think. Have you seen any results from that yet? What are your expectations? And I guess, in turn, what do you expect from Ivar Aasen, where production has been a bit weaker this year versus last year? And is there any guidance you can give us on when Symra and Solveig will be coming on stream next year, that would be helpful.

Okay. Let's first talk about Omega Alfa. So Omega Alfa for us is a test bed for basically 2 technologies -- or 3 technologies really. So it's, of course, wired pipe, which we really try to see what the operational envelope of that technology is. And I think during Omega Alfa and this extremely long horizontals, we've discovered that. Wired pipe will now be used on all Aker BP rigs, both in exploration drilling and in production drilling, as we made a strategic decision to move as fast as we possibly can into wired pipe technology. So I think that will be basically the standard now across all our drilling operations.

And then the other test case was basically to see how downhole drilling tools and logging wind drilling tools were interacting with these technologies and trying to optimize the drilling sequence, as Hanna talked about in her video. I think there are more debottlenecking to be done before we attempt that again. But there is quite a strong force or task force working these topics, both from the supplier side and from us as an oil company side. So I'm expecting that in a few months, we'll have debottleneck also that process.

And then the last one is the whole kind of the data ecosystem, right? Because this is basically about understanding the drilling process and being able to model and use machine learning to optimize the process. Also here, we have discovered some bottlenecks and are in the process of modifying those. But as I said, you should expect that these technologies and these ways of drilling these wells are not only going to be a part of our exploration program going forward, they are going to be a part of our production drilling program going forward. This is one of the reasons why we test the barriers that Hanna talked about in the video.

On the specific question on this, I don't think a lot of these wells that are currently on the program with the exception of inclusion of wired pipe will basically lend itself to this kind of exploration method. But what you could say is that it gives us an optionality if we make a discovery to very, very rapidly do appraisal drilling and acquire a sufficient amount of data to rapidly move from exploration and into a feasibility phase and from there to a development phase. So it basically opens up the toolkit. Omega Alfa in itself was, in my way, a way of basically testing where the current technological barrier was. And I can assure you that we found it on many levels.

Grieg Aasen, yes, we have drilled a few infill wells, 2, if memory serves me right. They are either just set on stream or about to come on stream. So I think the results are pretty much as expected. And the net results will, of course, be a part -- or are part of our production guidance going forward.

And then your discussions around Aasen, and I agree that this has been a bit weaker this year. This is partly because of lesser performance than we expected from Hanz, but also because we have higher performance from Grieg. And as we're now optimizing the area, that means that we have a bit lower production from the Ivar Aasen area into that totality.

And then your last question was...

I think it was Ivar Aasen IOR campaign next year.

Was that right, Victoria. Was that the last question?

It was just on the timing for the advent into Symra and Solveig.

Yes. Well, we haven't been very specific. But you're absolutely right, they will come on stream in 2026.

Next question is from Irene Himona from Bernstein.

Congratulations on the numbers and the exploration success. I have only one question on distributions. For 2026, your guidance is for production to dip and for leverage to move up. In your stress scenario of $50, leverage would move above your 1.5x ceiling. Currently, of course, commodity prices are weakening. You told us you're not hedged into '26. I just wanted to understand whether you would consider a, let's say, 1-year holiday to the aspiration to grow the dividend at 5% in the event that we approach your stress case in order to protect the balance sheet?

Yes, you want to talk about distribution, David, and the holidays?

I can do that. I can definitely do that. So the current value creation plan that we are in the middle of, that's something that we have planned for since end of 2022. And we came into this period with a lot of financial flexibility and low leverage. And through the investment cycle, we have been increasing leverage to invest in growth. When you look at the, call it, stress test scenario or the $50 scenario that I presented today and which is similar to what we also showed in the last quarterly presentation, that's assuming a $50 oil price from the start of 2025. So I mentioned that, that is probably too conservative of a case when you think about '25 in isolation at least.

Who knows what oil price will be in 2026. We are currently trading at around $62. We have the financial flexibility to withstand volatility. And we've been very clear on the ambition of the company to grow the dividend by a minimum of 5% if oil price is above $40. When it comes to leverage ratio targets, what we have said is that we don't want the leverage ratio to exceed 1.5x for extended periods of time. So we are comfortable to exceed that for a shorter period of time when we know that when production of the new assets comes on stream, we will be deleveraging back down again. So that's how we think about it holistically.

And then if I may, David, I think when thinking about low oil price scenarios in Aker BP, it's worthwhile looking at the history where we've been quite good in utilizing these periods of low oil price and being countercyclical. That will also be the case if we end up in a situation where the oil price dips down to $50 a barrel. I think there are many companies who will struggle significantly more financially than Aker BP will in that scenario, simply because of the strength of our balance sheet, the low cost and therefore, the high cash flow that we have in that period. So while all things equal, we, of course, like high oil price scenarios better than low oil price scenarios, I think it's fair to say that I'm also a bit ambivalent on these low oil price scenarios because they do create a lot of opportunity for companies like Aker BP.

Next question is from Chris Wheaton from Stifel.

Chris is on silent.

We can't hear you, Chris. I think we'll move to the next caller and then come back to Chris once he fixes his audio. Next question will then be from Matt Smith from Bank of America.

Perfect. A couple of questions from me. The first was on Johan Sverdrup. I mean, given the strong performance year-to-date and now what you're seeing from the multilateral performance, I just wondered if that's changed your expectations at all around how and when the project will come off plateau. So it would be the first one.

And then second one back on to the dividend. Rather than ask you about dividend holidays, I really wanted to ask what would give you the confidence to raise the dividend beyond the 5% per annum. It seems like you're very happy to do that in a $60 oil price environment, although correct me if I'm wrong. So it seems to me that this relates a lot to derisking your growth projects. So are we there yet? Or do we need to get much closer to first oil to unlock upside to that 5%, please?

Yes. So first, on Johan Sverdrup, and I can do that because it's relatively easy. And then David, you can answer the hard questions around dividend. So when it comes to Johan Sverdrup, we are pretty much spot on our internal expectations on the Johan Sverdrup performance. So in short, that makes the answer to the second part of your question quite simple. There are no reason to make any changes to our expectations to Johan Sverdrup that has been previously communicated to the market. So we're pretty much spot on.

David, dividends. This time, increase of dividends.

Yes, exactly. Well, I think when you look at Aker BP, the dividend capacity that we have is large. And we have, call it, a fundamental philosophy that all the value that we create in Aker BP will be distributed back to shareholders. The policy is a minimum of 5% per year increase through this investment cycle. And if you look at the history, we have exceeded that, call it, minimum threshold on multiple occasions.

With regards to giving you sort of yardsticks with regards to what would we need to see in order for that to be more than, call it, 5%, I don't think I will go into that discussion. That's obviously a Board discussion following also for guidance for next year. So what I'll say here is that the base case for Aker BP is a minimum of 5%, and then I'll stop there.

All right. Now let's make another attempt with Chris Wheaton from Stifel. And we are still not hearing you, Chris. So we'll circle back to you later, but we'll take Mark Wilson in the meantime from Jefferies.

Okay. Matt beat me to the question on Johan Sverdrup. You say it's pretty much spot on internal expectations. That was, I believe, for the plateau to last well into 2025, and that's where we are. So I guess the assumption is then that this starts to come off plateau into '26. But added to that, I think the most important thing you said to me, this making wired pipe standard on both development and exploration, you're seeing the advantages and the benefits coming through. My question, therefore, is that a standard that Equinor would be using on Johan Sverdrup? And more to the point, even if it isn't, could you explain how that would benefit, let's say, for any forward production expectations for, for instance, major developments like Johan Sverdrup and indeed the whole Edvard Grieg area?

Okay. So the 3 key benefits of wired pipe are basically a lot better -- the basic underlying principle is that you now have an ability to communicate with the downhole tools on a megabit bandwidth and not on a single-digit bit bandwidth. So it's a fundamental step in your ability to transport information in the well.

Then it also gives you information on the pressure and temperature and the, call it, fluid movements throughout the well from the very end of the drilling bit all the way up to the rotary, right? So that's the basic technology. That gives you 3 advantages. One, total control of the well at all stages. So you're much better at anticipating what's happening. Two, you can actually drill significantly faster because you're not limited by empirically model, but by actual restrictions as measured in the well. And then three, it gives you an ability to move from manual control to autonomous control because you now have a data stream that goes all the way from the bit all the way to the rig equipment. Those 2 are basically transforming the way we drill and basically means that we can increase ROP in almost all sections.

The upper sections will, of course, be limited by the total volume of rock removed from the ground and therefore, the kind of solids handling on the rig, whereas the lower sections and particularly the reservoir sections, they are basically limited by our ability to steer. And this is one of the reasons we're interested in this. So think of this as a fundamental step-up in performance, but also a fundamental step-up in our ability to place the well inside the reservoir and therefore, increase ultimate recovery. I think those 2 are basically universal truths for pretty much all production drilling, while they might be more valuable for highly complicated reservoirs than for reservoirs like Johan Sverdrup, where the drilling is actually quite simple.

Okay. So therefore, the reservoir model for larger reservoirs like Johan Sverdrup is not necessarily going to be affected by this, to your point, outside of East Frigg or the Omega Alfa. Then which other producing fields that you use do you think would be benefited, therefore?

With the exception of Valhall, pretty much all of them, simply because you are increasing your drilling speed and you have better control over the rest. So Frigg Gamma Delta, which is a prior dominant case in the Yggdrasil development is obviously an interesting one. But also drilling in Alvheim, we're following thin oil layers, and the Frosk and the [ Froskatic ], things are ahead of us at the moment. We just entered into the license in Kjøttkake after the discovery. That's also an injectite where you can see the same benefits as in Alvheim. So quite a few of these, call it, more challenging reservoirs will be -- it will be highly beneficial to utilize this technology. And that goes for also all infill drilling and IOR drilling.

Let's make one last attempt to bring in Chris Wheaton, who had a question and obviously had some trouble with the audio.

I hope you can hear me now.

Absolutely, Chris.

I'm sorry. This is -- I'm sorry to be the last question and keeping you from your day jobs. Two, if I may. Firstly, could you talk about the risk mitigation you're looking at about the offshore construction phase of the major project, because this is the point at which your construction process starts to interact with everyone else that's also going offshore in the next 2 years because of the Norwegian tax changes of 2022, which means that it feels like a lot less of the construction process from here is in your control and a lot more is down to other factors like weather and what other people are doing. And I'm assuming other people aren't going to be as good as you. So could you talk about those mitigation factors? Then I had a follow-up on another question about the exploration.

Yes, sure. So first of all, in terms of conventional field development, you usually have quite a bit of hookup and that kind of construction work offshore. That is not going to be the case for these fields. These are going to be installed pretty much complete and the only remaining work of volume will be commissioning work.

And then when it comes to risk mitigation, we now had behind us 2 very, very active offshore seasons where we have produced in excess of 1,400 offshore days of installation of pipe, templates, jackets, et cetera, et cetera. And in many ways, the majority of the offshore construction in terms of complexity is actually behind us. What is ahead of us is the topside installation, which will rely on weathers essentially, but where the capacity is actually quite good in the 2026 season.

And then we have 2 remaining pipelays in the next season. And then it's basically standard, I would call, stuff work where we hook up subsea templates and pipelines and that kind of thing. So the risk in the offshore construction, if there was a big risk in offshore construction, would be probably more in the 2025 season than in the 2026 season, even though the kind of the volumes installed in terms of tonnage will obviously be higher in '26 than in '25, but the complexity is actually lower.

Okay. That's very clear. Second question I have was on exploration. If you include your success at Omega Alfa this year, total discovered volumes on the NCS since 2011, so the year after Johan Sverdrup was discovered, adds up to just a bit less than 1 billion BOE. Norway is producing 1.4 billion BOE a year. What does that exploration or that lack of exploration success mean for the way Norway has to do exploration in the future? Is there a strategic reason here that actually you need more consolidation of exploration processes to get better resource recovery, which is ultimately what the government is going to want out of this whole -- want the industry to deliver out of the whole exploration process.

It's a good catch, Chris. So the simple answer is that we need to get a lot better. So even though we end up with, let's call it, 100 million barrels in 2025, production is probably ending up more like the 180 million or slightly lower than 180 million. So even with that kind of successful program, you won't reach to a reserve replacement rate of 1. That means that there needs to be some sort of either step change in exploration success and/or some sort of consolidation in order to reach those targets.

When it comes to exploration success, this is one of the reasons we're so focused on use of artificial intelligence, digital tools and match that to our rather active program into the upper rounds the last 4 years. So it will be a balance between our ability technically to prioritize the right targets and then drill them out with speed and efficiency, and then go very quickly from exploration success to field development and initial production. So we're trying to compress that whole time schedule.

The second one is, of course, understanding the reservoirs and understanding the Norwegian continental shelf. So we are deploying significant amounts of capital and resources to develop agents and technologies that allow us to access every data point that's ever been amassed on the Norwegian Continental shelf. Currently, we're in a situation where we can investigate everything that's been publicly publicized and also that we've gotten through different processes inside Aker BP, whether that is structured information or unstructured information using artificial intelligence and agents. And that's basically allowing us a much better view on where we believe, call it, the secondary migration routes and the remaining potential is on the Norwegian Continental Shelf. So you're absolutely right, there needs to be a step change in order to deliver this.

And then kind of going back to what we -- I think we discussed in the second quarter. I don't think it was you who asked the question, but I basically boxed these remaining resources on the Norwegian Continental Shelf down to 3 boxes. It's what I will call subsea tiebacks, IORs, so smaller volumes. Then you have tight reservoirs, where we have large volumes of discovered oil in place, but currently very few developments. And second, there are HPHT, which haven't really been developed to the extent it has been on the U.K. Continental Shelf, for example.

So if you take that checklist and you look at our current and past project execution, you will see that we have, for a long time, tried to become the master of IOR targets and field developments and subsea tiebacks. I think we're pretty good, trying to get better. Fenris was our test case or exam, so to speak, on HPHT, and we're now past the drilling campaign on Fenris, discovered more volumes than we assumed. So there might be one additional well in 2027 on Fenris. And then we are in the process of dipping our toes into tight reservoirs. So both becoming significantly more productive in exploration, but also amassing and assessing and ultimately producing the resources that exist in those categories. Those are 2 basic lines of thought when it comes to the organic side. And then as you know, we are always up for a good deal if that happens.

Then back to the quizmaster.

Yes, there seems to be no further questions. So I'll leave it back to you.

Thank you. Then I say thank you for following us this morning. We will continue to do what we do best here in Aker BP and that is to produce, develop and discover oil and gas also in the next quarter, and I'll see you in about 3 months.