Aker BP ASA ($AKRBP)

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 onstream 9 months ahead of the original plan. And a 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 a 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 tieback program. This year, production has started at Johan Sverdrup Phase II and Symra tied back to existing infrastructure in the Edvard Grie. 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 tied back to Alvheim and 3 tied back to Eiga. Momentum continues at scale where the 3 tieback 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 tiebacks 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 contract involvement and aligned incentives. The results are repeatable and a competitive position in the subsea tieback execution on the NCS. Alongside our tieback activity, execution continues on our 2 major development projects. Both Brazil Yggdrasil and Valhall PWP foundries 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 Sailaway. For Hugin A topside, Sailaway 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 top site. Construction of the PWP topside is progressing at the storeyard 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 us show you what this quarter installation looks like in practice. [Audio Gap] This is large-scale project execution. Together, our tieback portfolio and the major developments provide a balance 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 where it's important to reinforced by a broader focus on energy security. The activity was lower in the first quarter but has now picked up. In the Johan wardrobe, the Tonjer exploration well was completed in early May and confirmed volumes in line with the predrill 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. AkerBP'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 data. 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 data 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 rent 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 costs 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 on the 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 tieback 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 tiebacks 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 of 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 Bi.

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

Now we hear you. Yes.

Okay. Okay. Perfect. Karl, you highlighted the strong economics of your recent tiebacks and your remarks with $27 a barrel breakeven and very I mean, quite attractive IRR. Would it 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 taking 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 tiebacks 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 lower oil prices.

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

Can you hear me Okay? .

Talk to you, James.

Can you hear me again?

We can hear you.

Okay. Just -- so just thinking about the realization points that you made in terms of data reverses futures, et cetera. I'm just wondering if there's anything we need to think about for tax purposes and 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 hotbed 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 price. 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 sustaining production on Slide 4 in the presentation that I just went through, you can actually see the distribution of the profile into the. And as you see, the GAAP, 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 are 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 color is Teodor Sveen-Nilsen from SpareBank 1.

Karl and David. Two questions for me. First, on summer maintenance this year, is attempting 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 -- what is the status there? And what kind of work is going on? And how should we think around the timing of FID.

Okay. On some maintenance or turnarounds, 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 listing, 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. .

Yes, if my count is correct, you have 5 top sites that are planned to be installed this year. The first 1 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 Monigan the second 1 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 was 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. It's 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 it's 2026. Is it like a deadline where the window is shutting?

For Hugin A you mean?

Yes. .

No, not really. The almost counterintuitive here. So Hugin A is a top side 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 -- how we 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 also -- we all remember the bars problem with the YutanFTSO where the headlines seem to be late August for Salway .

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, and you mean Hugin A and the last 1 is Valhall is that correct? .

That Is correct. That is the yes.

My final question, I understand that it might have been -- or at least I've heard that this hotel strikes has impacted some of the arts 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 store. 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've 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 as 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 utilization afterwards.

Yes.

So you're absolutely right. When construction is going on at full blast to, there is about a little above 10,000 FTEs in rotation. Obviously, as you are moving towards sale away, 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, unshoed onshore activity to the offshore activity. And then as you're ramping up offshore with drilling rigs and yes, all the associated activity, the kind of -- the spend level comes up a little bit, right? So that basically the planning consequences or 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. So I think overall, the cost performance have 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 we 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 cost 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 NOC exposure hedged at rates between NOK 10.5 and NOK 11 per dollar. And you can actually also see the effects 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. Unitization?

Yes. So very simply put, East Frigg had a different ownership profile than the Frigg Gamma Delta unit. The previous cost estimates or let's 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 contract 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 trick now in the first quarter is when the actual accounting effect of this has happened and also the true contra. 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 is 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 how the improved oil price curve change 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 project in guidance. So first of all, I absolutely do agree with you, Nash, 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 and, call it, surprise to us. What 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's quite clear that there will be a consolidation game on the Norwegian Continental a 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 months will succeed. It is also quite clear that going forward, you will see a different profile on the Norwegian Continental self dominated by subsea tiebacks 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 tieback. I wouldn't call it factory but value chain with the alliances, a digital execution module and the whole aperture around that. That is now demonstrated that at least in my mind, is -- yes, I would 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 gilet. 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've been working with tight oil and tight gas on 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. Two main drivers there. I would say excellent results and modifications on the platform, Alvheim, Eiga. Great drilling results. and on-time subsea deliveries, no quality incidents. Those are the main components. On Scout satellites, I would say I have never seen this kind of performance on an option 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 this project, 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?

Sashi, good to see.

Yes. SP84010290 My question was on Johan Sverdrup. We saw a 5 year -- 5% year-on-year decline in 1Q, high production efficiency, optimization and new well contributions all offsetting natural decline. That'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 your answer I can definitely do the job.

I think as we've talked about many times before, the performance on Sverdup 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 -- so there's no specific news there with regards to add. 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 Vans Werder Phase 3 progressing well. .

All right, then we give Alejandra another chance because I think I heard her. Alejandra are you there? Now there seems to there -- there she is.

Can you hear me?

Yes, we can. Good 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 Joanne Burrup 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, higher 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. Ted 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 in that field. That also goes for the drilling operations and the well operations. The retrofit multilateral may be slightly better than our expectations, but well within the uncertainty parameters, I would say. -- strength that is my view that we will need to see more of this kind of activity going forward. But again, mostly in line with our expectations. .

Thank you. Then we move on to Anders Rosenlund from SEB. Thank you. 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 word -- way you're putting it. My second question is, if you could talk about commodity price hedging and the opportunity to buy more puts in particular, on the oil price, it seems like you've done some in Q1.

Yes. Great. Anders. It's great hear somebody else from Bergen on this call to Well, -- there is, of course, a little bit of semantics on this. So our view is to sustain production above 500,000 well into 2030, 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 8 Hedging. Yes. Okay.

So we continue to 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. Okay. Thanks .

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

Just 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 SP1 I think the final question is definitely 1 for you, for me Okay.

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 a 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 at these times. So I'll leave it at that.

Okay. In the hypothetical side, or prices did normalize at some point, does that impairment we 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 your 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. Thank you. Bye-bye.