Aker BP ASA (AKRBP) Earnings Call Transcript & Summary

Good morning, and welcome to Aker BP's First Quarter 2025 presentation. As usual, I'll start with a brief update together with our CFO, David Tonne, before we open for questions. But first, I want to take a moment to look at the bigger picture. We are operating in an environment marked by increased uncertainty. Armed conflicts are ongoing, and political tensions have created uncertainty around the framework for international trade. This, in turn, is fueling concerns about the global economy and the outlook for energy demand. At the same time, we are seeing significant currency swings and heightened financial market volatility. It is in the midst of this that Aker BP remains in a strong position. We have a robust balance sheet with high financial flexibility, industry-leading low operating costs, and we are investing in projects that are highly profitable and resilient to low oil prices. We have secured most of our foreign exchange exposure for the next 2 to 3 years at attractive levels. And we are, to a very limited degree, impacted by the turmoil around tariffs and trade. This puts us in a position to stay focused on what really matters: running our business efficiently, investing with discipline and creating long-term value for shareholders even in uncertain times. In February, we hosted our annual strategy update where we focused on 4 key themes. The first are distinct capabilities, including a strong performance culture, digital leadership and our alliance model, which fosters closer collaboration with our suppliers. In the first quarter, we continued to build on this foundation. A good example is the 5-year extension of our well Intervention alliance with SLB and Stimwell Services. We are also seeing strong momentum in the rollout of artificial intelligence tools across the organization. The second was a world-class asset portfolio. As we'll show shortly, we have delivered yet another strong quarter characterized by high efficiency, low cost and low emissions. The third theme was growth. And as you know, we are progressing a series of field developments that will lift our production to more than 500,000 barrels per day by 2028. And we remain firmly on track. Since the strategy update, we have also made 2 new discoveries and we have several exciting exploration wells coming up in the months ahead. And finally, we highlighted our financial framework built on a resilient balance sheet and strong cash flow generation. This gives us the flexibility to continue investing in high-return projects while also delivering attractive returns to our shareholders. As I've mentioned earlier, that is especially important in today's uncertain environment. Now let's dive into the details. Production for the quarter reached 441,000 barrels of oil equivalents per day, significantly exceeding our full year guidance of 390,000 to 420,000 barrels. This performance was largely in line with our expectations for the quarter. A notable contribution this quarter came from Alvheim, particularly from Tyrving, which commenced production in September last year. Despite a couple of brief power outages at Johan Sverdrup and some planned downtime at Valhall due to preparations for the PWP drilling campaign, we achieved an outstanding production efficiency of 97% across our portfolio. Looking ahead, we have scheduled maintenance for several fields in the coming quarters. And overall, our current forecast suggests that we will end up within the full year guidance range. Production costs for the quarter were $6.5 per barrel, slightly higher than last quarter, but well within the full year guidance of around $7 per barrel. This remains a highly competitive level compared to industry peers and reflects continued strong cost control across our operations. The same applies to our greenhouse gas emissions where we continued to rank among the companies with the lowest CO2 intense -- emissions intensity in the industry. In the first quarter, we saw a slight uptick in intensity mainly due to high drilling activity and somewhat lower production volumes. That said, we remain firmly committed to our long-term emissions strategy. We are working systematically to eliminate avoidable emissions across the portfolio, and our plan to offset residual emissions from 2030 for nature-based carbon capture remains unchanged. The Johan Sverdrup field is a key asset in our portfolio so let me cover this in a bit more detail. The field delivered outstanding performance in the first quarter with high production efficiency, low operating costs and excellent safety record and minimal emissions. Looking ahead, several activities are underway to unlock even more value. Drilling at the field center will continue with 2 new wells completed and brought online so far this year, bringing the total number of production wells to 41. Our 4-well retrofit multilateral campaign is scheduled for this summer. This involves adding new lateral branches to existing wells to boost production without adding new infrastructure. As a result of these efforts, we expect 2025 production to remain close to the levels seen in 2023 and 2024. Beyond 2025, there is more in the pipeline. The Johan Sverdrup Phase 3 project, which includes 2 new subsea templates and 8 additional wells is progressing towards a final investment decision this summer. In parallel, we are maturing new infill and exploration targets in the area. Altogether, this supports our ambition to increase the field's recovery factor to 75%, one of the highest in the industry. At the strategy update in February, we presented our plan to sustain production above 500,000 barrels per day beyond 2030 and to pursue further growth. So to briefly recap, the dark blue area represents our current business plan, including production from existing fields, ongoing field developments and mature nonsanctioned projects such as East Frigg and Johan Sverdrup Phase 2 -- Phase 3 along with regular IOR activities. This outlook supports our target of around 525,000 barrels of production per day by 2028. Beyond 2028, the light blue wedges illustrate our potential to sustain production above 500,000 barrels per day through additional infill drilling and tiebacks from known discoveries across our portfolio. The progress we have seen in the early months of 2025 strengthen our confidence in this trajectory. Looking further ahead, we also see potential for growth beyond the current outlook. With continued exploration success and selective M&A opportunities, we believe that there is a clear path to further expand our production base into the next decade. This is our ambition, and we are well equipped to deliver it. We have the people, the assets, the suppliers, the digital ecosystem, the capital and the track record. Let's now take a look at our major development projects and see how they are progressing. The activity level is very high across all sites. Fabrication and assembly of topside modules are continuing at full speed. Jackets will be installed offshore, and production drilling is ramping up across all our key development projects. At Valhall PWP-Fenris, construction activities are advancing steadily while offshore modifications to the existing Valhall facilities are ongoing. We are preparing for the installation of the PWP jacket and bridge later this summer. The second of the 4 planned wells on Fenris was completed in the first quarter, and we're preparing to start drilling production wells at PWP this summer. The Skarv Satellite Project covers 3 fields, Alve Nord, Idun Nord and Ørn, all of which will be tied back to the Skarv FPSO. The 2025 subsea installation campaign is underway. And also here, we are preparing for drilling of production wells later this year. At the Utsira High project, we have successfully completed testing of the subsea equipment and the subsea installation campaign is well underway. Preparations for the 2025 drilling campaign are also on track. And to confirm, we are on track to deliver this project on schedule and on budget. This is also the case for Yggdrasil. Yggdrasil, as you know, is a key pillar for Aker BP's growth strategy. It stands out as our largest field development with first oil and gas planned for 2027. And I'm pleased to report that progress remains firmly on track. Construction and assembly of topsides and jackets are advancing at multiple locations, both in Norway and internationally. The Hugin A topside is taking shape at Stord, while the Munin topside is progressing well in Haugesund. Offshore, the installation of the subsea power cable has begun and we are preparing for a major installation campaign in 2025. This summer, we will install the Hugin A and the Munin jackets offshore and commence the drilling campaign using the rig Deepsea Stavanger. We are also moving towards a final investment decision for the East Frigg Beta/Epsilon discovery, which will be integrated into the Yggdrasil development. With this addition, the estimated total recoverable volume has increased from 650 million to around 700 million barrels. And we see a further upside. At our strategy update, we launched the ambition of reaching 1 billion barrels for Yggdrasil. And we have some really exciting exploration activities coming up shortly. This illustration shows our next exploration well, which will test 5 separate prospects along the same play that we proved with the East Frigg discovery in 2023. The combined predrill resource estimate for these targets is in the range of 40 million to 135 million barrels, and drilling is set to commence in the next few days. In parallel, we are maturing additional opportunities across the wider Frigg area. Following last year's APA round, we have added acreage around the old Frigg gas field. While the field was originally developed for gas, there are significant oil volumes in place across several Frigg structures and nearby discoveries. With modern technology and new geological insight, we see a large potential and we expect more exploration drilling in this area in the coming years. And while we are on the topic of exploration, we have an ambitious program lined up for 2025 with plans to drill 15 to 20 wells. Of the 6 completed so far, 2 have resulted in commercial discoveries. The first one was called Kjøttkake, an oil and gas discovery operated by DNO located northwest of the Troll sea platform in the North Sea. The well encountered sandstones of good reservoir quality with preliminary recoverable resource estimates at 38 million to 74 million barrels of oil equivalents. Aker BP holds a 30% interest in the license, and we are working closely with our partners to find a swift and profitable development solution. The second and most recent discovery was made in the E-prospect in the Skarv area. The main target yielded a minor oil discovery estimated at approximately 5 million barrels. And even though it's relatively small, we still believe it can be commercially developed as a tieback to Skarv. One well that has attracted a lot of investor attention is Rondeslottet where we plan to start drilling within the next few days. And due to the high interest, let me add some context to this important well. Rondeslottet is a significant structure and we know it contains oil. This was confirmed by the Ellida well drilled by Equinor back in 2003. The challenge lies in the reservoir quality. It is classified as a tight reservoir with low permeability and limited natural flow. Since that discovery more than 20 years ago, technology has evolved considerably, particularly for the developments in the U.S. shale. At Aker BP, we have successfully applied several of these techniques at our producing fields, especially at Valhall. And we do believe that Aker BP is among the global leaders in offshore fracking. According to the Norwegian Offshore Directorate, tight reservoirs on the NCS holds a substantial volume of oil and gas. And Aker BP aims to play a leading role in unlocking this major untapped potential. Rondeslottet is an important step in that direction. While we certainly hope that this well will provide valuable answers, it is realistic to expect that the appraisal drilling will be needed before firm conclusions can be drawn. That said, we are confident the insights gained will be highly valuable and help shape our approach, both the Rondeslottet in particular and to tight oil opportunities across the NCS in general in the years to come.

Good morning. As Karl just described, Aker BP delivered strong operational performance in the first quarter, marked by high production, low cost and good price realization in a turbulent market. This combination resulted in another quarter of robust financial results. Our financial position is further strengthened with ample available liquidity, low leverage and low net debt. At the same time, we are maintaining strong momentum across our project portfolio and investment program. And altogether, the first quarter marks another step forward on our value creation plan where we focus on maximizing shareholder returns by maintaining financial flexibility, investing in profitable growth and delivering a resilient dividend that grows in line with value creation. Let's now take a closer look at the main drivers behind the financial results. Net production declined slightly in the first quarter, but sold volumes increased from 439,000 to 458,000 barrels of oil equivalents per day, mainly due to overlift. Over time, lifting imbalances tend to even out and the positive impact in this quarter has largely offset previous underlift. On the cost side, operating costs rose to $6.5 per barrel from low levels in Q4 last year. This was mainly driven by more normal levels of well maintenance activity at Valhall and higher power prices in Q1. Despite the increase, our unit cost remains industry-leading and below our full year guidance of $7 per barrel. Cash flow from operations reached $2.1 billion in the quarter, a significant increase from the previous quarter. The improvement was driven by higher revenues, lower tax payments and a stable working capital. Cash flow through investments also remained stable at $1.4 billion, reflecting the continued high level of construction activity across our project portfolio. As a result, free cash flow totaled $685 million for the quarter, equivalent to $1.10 per share. Within financing cash flows, the main item was the dividend, which increased to $0.63 per share in the first quarter. Zooming in on another few items in the income statement. With both sold volumes and realized average hydrocarbon prices slightly up, revenues increased quarter-on-quarter by 4% to $3.2 billion. Production cost of sold barrels increased slightly more than the cost per produced barrel would indicate due to valuation of overlifted barrels. Depreciation increased both in absolute terms and on a per-barrel basis compared to the previous quarter. This was primarily driven by drilling activity in the Ula area where investments are immediately depreciated due to the short remaining lifetime of the field. Net financials contributed with a gain of $14 million in the quarter. The strengthening of the Norwegian kroner led to currency losses, mainly tied to the reevaluation of tax payables. However, these were more than offset by positive movements in the fair value of derivatives used for FX hedging. These derivatives are designed both to neutralize FX risk on tax payables once revenue is realized and to manage the Norwegian kroner exposure related to our investment program the next 2 to 3 years. We also recorded $189 million in impairment of technical goodwill during the quarter, which led to an increase in the tax rate of 84%. This goodwill is not tax deductible, and the adjustment is an accounting technicality. For more information on technical goodwill, including a short video, it's available on our investor website at akerbp.com. In total, net profit for the quarter ended at $316 million or equivalent to $0.50 per share. With the strong operational performance flowing through to the financial performance, we exit the first quarter with our financial position further strengthened. Net interest-bearing debt is down to $3.2 billion, and our leverage ratio remained stable at 0.3x net debt to EBITDAX. Total available liquidity increased to $7.7 billion, of which $4.3 billion is cash and cash equivalents. This can then be compared with the estimated remaining after-tax commitment of our ongoing investment program of less than $2.5 billion. As Karl has already covered, our portfolio of development projects is progressing according to plan. The CapEx outlook is virtually unchanged from when the program was launched in 2023. Only minor adjustments to the phasing have been made while the total capital expenditure estimate in dollars remained the same. Since the sanctioning of the projects, we have worked systematically to manage the Norwegian kroner exposure related to our investment program. We have now largely completed this effort with 75% to 100% of planned NOK expenditures for the next 3 years hedged at an average dollar-NOK rate between 10.5 and 11. This effectively reduces our exposure to the risk of a weakening of the dollar in the coming years. In Aker BP, we do not invest in growth for the sake of growing. We do it to create value, and we continue to progress on our 2023 to 2028 value creation plan. By 2028, we estimate to have generated between $9 billion and $14 billion in free cash flow, depending on oil prices, equivalent to 65% to 100% of Aker BP's market cap. In turbulent and volatile times, the focus of many external stakeholders turns to resilience. In Aker BP, we have prepared by systematically building the necessary resilience to withstand the volatility of the commodity markets through the cycles. On the right-hand side of this slide, we illustrate this with an estimate of how our leverage ratio develops across different oil price scenarios. Assuming a continued 5% annual dividend increase, we stay comfortably below our internal 1.5x leverage threshold in most scenarios and way below the bank covenant of 3.5x. And even in a prolonged $50 oil price environment, we only see a brief exceedance above 1.5x, followed by deleveraging from 2027. In summary, our value creation plan is on track, and we have the capacity and resilience for attractive shareholder distributions in the years to come. Now on the topic of shareholder distributions, let me briefly revisit our distribution policy. 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 plan to distribute a total dividend of $2.52 per share paid in 4 quarterly installments of $0.63. Let me also briefly comment on our projected cash tax payments for 2025. As usual, we paid 1 tax installment in the first quarter and 2 will be paid in the second quarter. As we move deeper into the investment program, annual tax payments are declining, which is clearly reflected in this chart. Taxes paid in the first half of 2025 are roughly half of what we paid over the same period in 2023. Tax payments due in the third and the fourth quarters will be set in June, in line with the new payment schedule that increases the number of installments from 6 to 10 per year. This illustration shows a range of possible outcomes based on different oil price scenarios for the year 2025. Thanks to the tax deductions associated with our investment program, we expect to pay very limited tax for the 2025 fiscal year at oil prices below $60. This is a key feature of the Norwegian tax system: it provides added resilience to market volatility when investing in profitable growth. Let me now conclude with a few comments on our 2025 guidance. The short version is simple, no changes, but let me add some context to each of the items. Production averaged 441,000 barrels of oil equivalents per day in the first quarter, above the top end of our full year guidance range, but in line with our expectations for the quarter. We anticipate some natural decline from certain fields as the year progresses along with planned maintenance activities in the summer months. Consequently, we continue to view the full year range of 390,000 to 420,000 as a fair estimate, but with Q1 now derisked. Production costs came in at $6.5 per barrel in the first quarter, supported by strong operational performance. And we still expect $7 per barrel for the full year given midrange production. CapEx is approaching peak levels with construction activity at full speed and drilling campaigns ramping up across several assets this summer. We invested $1.3 billion in the first quarter and maintain our full year guidance of $5.5 billion to $6 billion. Exploration is progressing in line with plan. The program is somewhat front loaded in 2025. And with only minor adjustments, we continue to expect total exploration spend around $450 million for the full year. Abandonment activities are also on track, and we maintain our guidance of $150 million. And with that, I'll leave the word back to Karl for some concluding remarks.

Thank you, David. We have had a strong start of 2025 with high operational efficiency, low cost and low emissions. Our development projects are progressing as planned, and we are approaching in a final investment decision for Johan Sverdrup Phase 3 and East Frigg. We have made 2 new discoveries so far this year, and we have an exciting exploration program ahead. The financial position remains robust, and our value creation plan is firmly on track. With continued discipline, strong execution and a resilient balance sheet, we are well positioned to deliver attractive and growing returns to our shareholders in the years ahead. We will now take a short pause before opening the Q&A session. [Operator Instructions] And if you prefer to listen only, please stay tuned and we'll resume in just 1 minute.

So thank you for listening in, and welcome back after that short break, and then we'll start with the Q&A session. And as usual, Kjetil Bakken, our eminent Head of IR, is running the show. Kjetil, who is the first to ask questions?

Yes. The first question today comes from Vidar Lyngvær of Danske Markets.

Congrats on the quarter. Very solid delivery. Quality is just what we want today, and you bring no surprises. Thank you for that. CapEx excluding exploration and decomm came in at about $1.3 billion in Q1, suggesting a run rate of less than your full year guidance. That's also unchanged from $5.6 billion to $6.0 billion this year. Had you expected Q1 to be below the full year run rate? Or is something slowing you down in Q1?

Thank you, Vidar, and thank you so much for the appreciation. CapEx is pretty much spot on where we expected it to be. So because of the phasing of deliveries, and a lot of this is actually procurement, we expected a bit lower run rate in Q1 and a bit lower also in Q2 and then ramp up as we get towards the back of the year. And this is why we have maintained our guidance. We think that, that is a good assessment of where CapEx will end up this year. And then, of course, we've been believing that we would be substantially below the guided CapEx. That is not what we want. We actually want, at this stage, to be a little bit more aggressive and forward leaning when it comes to CapEx utilization. So pretty much spot on our internal expectations.

Well understood. Could I also ask about power-from-shore electrification of assets on NCS that's pretty popular. Where do you see -- what's your impression on how European majors look at that like the BPs, the Totals, the Shells? Is that well understood there as well? Or is there more confusion around that in South of Europe?

I think that's a little bit of a -- I think there's a lot of opinions around that topic. So from an Aker BP perspective, there are 2 main drivers for electrification and particularly usage from power from shore. So the first one is obviously to reduce the greenhouse gas emissions intensity. But I think the largely overlooked benefit is the fact that we actually get higher operational efficiency, lower downtime and an easier way to automation with power-from-shore compared to local power production. In other jurisdictions, there might be more restriction when it comes to transfer capacity. Power prices might be higher. There might be other installed bases that don't lend itself to electrification the way the Norwegian Continental Shelf will. So I think that will -- you will hear many opinions on that depending on where you are on this planet.

All right. The next question comes from Sasi Chilukuru from Morgan Stanley.

I had 2, please. The first one, I was just wondering if you could provide more color on the financial flexibility you have to navigate a scenario where oil prices fall further from here and for longer. Appreciate the balance sheet strength and the gearing level staying below or at now 1.5x in the stress test scenario. I was just wondering if there was anything that can be done to support the cash flows in such a low price scenario. The second was on exploration. The campaign for 2025 has seen a few more additions. But the guidance for exploration CapEx has remained the same. I just wanted to understand if this was because these additional wells were already anticipated in the plan or is it because you're saving on the exploration spend for these additional wells?

Thank you, Sasi. I think I'll leave the financial flexibility question to you, David. You might be a bit disappointed if I didn't do that.

Yes. No, that's true. That's true. I think in terms of finance flexibility, you pointed to it, Sasi, right, so we have prepared for volatile times. That's been part of the strategy of the company ever since 2014. So we have low leverage, no material debt maturities before 2027. We have high financial capacity, $4.3 billion in cash on account and under an RCF, and that's a lot of the financial flexibility that we use in order to manage through sort of the volatility in commodity prices. When it comes to the CapEx program that are currently ongoing, of course, there's a lot of flexibility in the sense that these are highly profitable projects. So very low breakevens, sanctioned between 35 and 40. And now that we have progressed projects leaving a lot of CapEx behind us, the breakevens of the projects, obviously, point forward goes down. And when these projects come on stream, we typically talk about a payback time of 1 to 2 years. Looking ahead in time, of course, there's flexibility around what do we sanction going forward, but that's something that's further ahead of us in time. So I think the key message here is that we are prepared for market volatility, and we continue to progress as planned.

And then on exploration, and I appreciate the question. So the 3 major changes from the exploration list or a list of wells that we presented in February. So first one, we have converted what we had as contingent slots into no named slots. So there are 2 additional wells that you probably won't see on the February list that you can see now on the Q1 list. Two, we have split out the exploration targets in -- going to be drilled in the Yggdrasil area, the Omega well, which we have referred to previously, has now been split into separate drill tracks. And then lastly, because of improved performance, we have added one more well to the list in 2025 that was not a part of the original 2025 program, but was supposed to be drilled in 2026. So that is why we've ended up now with basically the same cost estimate. But as you correctly pointed out, we have converted 2 slots into named slots and added one well. Good catch.

All right. Then the next caller is Teodor Sveen-Nilsen from Sparebank 1 Markets.

Congrats on a strong quarter. A few questions for me. First on Slide 10 when you talked about M&A as a whole lever of growth, I just wonder if you could comment on how the recent market turmoil and tariffs and potential OPEC production increase has impacted the NCS M&A market or if there has been any impact at all. Second question, that is on the maintenance season. Should we model most of the maintenance this year in Q3 or Q2? And if you could provide any specific numbers, that would be useful. And third question that is on general E&P CapEx. Over the past few weeks, we've seen many of your peers reducing E&P CapEx. Do you think that is too countercyclical? Or is that a fair decision to do when you see the current macro environment?

Yes. So you referred to Slide 7. Yes, historically, we have been rather active in Aker BP and utilized situations where other companies with less financial flexibility and less operational efficiency have been either forced to sell or determined to sell. I think we are heading in the same direction right now. I think there is a situation where due to low oil prices and other, call it, capital allocation mechanisms, there is an opening of activity on the Norwegian Continental Shelf. And obviously, this is now a buyer's market -- or seller's market, sorry. So there's a lot of activity, but the prices right now is not necessarily where we are interested in. That being said, we -- having said this all the time, there hasn't been a day I've been CEO of Aker BP we haven't had at least 1 M&A project running, and that is still the case. Maintenance, 2 major maintenance activities this year. So the first one is in Q2 on Valhall, and then we have another activity as we approach September. So you would be correct to model this in both Q2 and Q3. The total impact is included in our estimates, and I'm not going to give detailed information as to how many days and which fields, et cetera, et cetera. Come back to that as we approach Q2 and the actual results. And then your final question was regarding CapEx investments and possible scale backs. I think my view on that, and this is basically talking about our Aker BP and others will have to talk about their companies, when we made the decision to invest $19.4 billion, $19.7 billion back in 2022, we always assumed that as we were progressing this project there would be volatility. And we have prepared for that situation by ensuring sufficient liquidity, by making sure that we are not directly exposed to the FX change, et cetera, et cetera. In history, if you look back, following these trends and underinvesting as the oil price drops have turned out to be a poor strategy, whereas maintaining the activity level and making sure that you are actually investing in situations where the oil price is low means that you have a higher production as the oil price recoups, and therefore, also have a higher profitability over time. The second is more -- the second topic is more industrial in nature. It takes actually quite a lot to scale up and down investment activity. As you scale up investment activity, you go through a learning curve inadvertently. As you scale down, it has reduction costs. So you kind of lose on both ends, right? So you have to make sure that as you are scaling these projects, and I don't have the details on what the different companies are doing, but this is actually worth risk and cost of changing rather than executing.

That's clear. Just on the first question on M&A again, did you say that you still believe it's a seller's market on NCS?

Right now, I think there's an influx of companies that want to participate on the NCS. Yes.

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

David, on your Slide 22, you mentioned that $50 is like the stress test where you see that it's getting slightly above your own targets in terms of leverage. But if you're going to say it in one number, do we interpret -- do I interpret you correctly when I say that $50 is the level where -- above $50 your current dividend should be sustainable for the foreseeable future, you're going to give $1 on oil price level?

On the exact oil price. So I've said this in the past and I'll say it again, so our ambition is to grow the dividend by a minimum of 5% per year if the oil price is above $40. And the illustration that you're referring to on Page 22 is the same illustration that we used in our capital markets update in February, and illustrates a scenario where the oil price is $50 from the start of this year and throughout the whole investment cycle or value creation plan, as we call it, throughout 2028. And that's where we are illustrating. Even in such a scenario, leverage ratio will only exceed 1.5x net debt-to-EBITDAX for a short period of time before deleveraging. But the ambition of increasing the dividend goes also below that oil price level.

And the ambition to increase 5%, could you remind me if you said until 2027? Or it's beyond '27?

So what we have said is that the ambition is a minimum of 5% through this investment cycle and this value creation plan, which has gone from 2023 to 2028, and that's as far as we have talked about that.

And my second question goes to Karl. I appreciate that investing now is -- when oil price is low is good because we get the production when the oil price is higher. But I guess you have some production wells that are -- have relatively short production life. And as such, could be tempting to save for higher oil prices. Do you have any of that at all? If you have seen any considerations like that where you find -- where you decide that it's better to hold now -- hold on and wait a little bit and produce a little bit lower -- less now and save it for better times?

Yes. Thanks, John. I'm actually quite poor in predicting the oil prices. So I think the starting point is I wouldn't know exactly on when to put them on the rig schedule because that would mean that I would predict exactly when the oil price was ticking back up again. In reality, I think my view on this is that steady as she goes, making sure that each quarter, each month, we basically drive our proportional efficiency, we increase our performance is the way to actually execute it. And then we have to live with the fact that the oil price will be volatile and will change in a pretty unpredictable fashion. I think it would be almost borderline arrogant of me to basically start moving operational activities around on a pretty complicated plan because I had an idea of when the oil price would change.

And maybe if I could just add also, John. I mean, if you look at the current market environment, we're talking about an oil price of $60, which is actually quite attractive if you compare to what the breakevens of what the type of projects we invest in are. So if you look at the full project portfolio of Aker BP, right, at $65 Brent, we have over 25% IRR across the portfolio. So we are creating a lot of value by investing in this price environment as well.

And the wells you're talking about is even better, right? So the wells where you have a lot of flexibility are basically IOR infill wells, which, quite often, have even better economy than the full scale life cycle projects.

The next caller is James Carmichael from Berenberg.

Just a couple of quick ones. Just on -- just interested in the sort of tight reservoir expertise that you described. I was just wondering if there's any sort of context that you could give around maybe the scale of the opportunities that you think exist in the portfolio. Obviously, Rondeslottet is a big one. But are there sort of other areas in the current asset base? And then just a second one, can you just maybe remind us on the process or timing for the redetermination of the Johan Sverdrup 3?

Yes. When it comes to tight reservoir, one of the characteristics with tight reservoir is relatively high stowage, right? So the actual in-place volumes are pretty high. Two examples maybe. Rondeslottet, which is maybe in the range of 1 billion, 1.5 billion in terms of oil in place; and then Miocene, which is the horizon above the original Valhall reservoir, which is another 1 billion. So you're actually talking about pretty big accumulations from an in-place perspective, right, which makes this attractive. So the price of actually cracking this nut, so to speak, is quite high. And why it hasn't been done before? Well, the complexity is also quite high. And there's a lot of technology and expertise that needs to go into this to make sure that we are creating economic projects out of these type of projects. We do believe, however, that as you are progressing the development of the Norwegian Continental Shelf, tight oil, high pressure, high temperature, and call it, small tiebacks will be a large part of the remaining resource base. And we are focusing on developing expertise within all of these 3 areas. Small tiebacks, we've been doing quite a lot on the projects. So yes, so far, in Aker BP, Fenris is the acid test of our high-pressure, high-temperature capabilities and that seems to be going quite well. And then we have, of course, spent quite a lot of time developing expertise within tight reservoirs and are now moving that up a notch and drilling Rondeslottet, which are just spudding. Then your second question was on...

Redetermination.

Redetermination. Yes, that process is ongoing. And I am not going to spend a lot of time discussing it. We'll get back to that when the results are more communicate-able.

Yes. Next question comes from Victoria McCulloch from RBC.

A couple of questions from me remaining. You've got a really active exploration profile for this year. But I guess it looks lighter in the Barents Sea. Could you maybe talk about your medium-term outlook for opportunities in the Barents Sea that you see and you could add to the exploration opportunities in the medium term. And then on Sverdrup, can you give any context on the upside that's being achieved from retrofitting multilaterals? And is there any chance that more of these could be added to the schedule this year?

Yes. So let's talk about the Barents Sea first. Thank you for your questions. I think when it comes to Barents Sea, we are not really differentiating in terms of exploration, whether it's in the Norwegian Sea or the North Sea or the Barents Sea. We're basically using the same decision criteria on all wells. That being said, we have been quite active in the Barents Sea historically. We have tested quite a few of the existing exploration models in the Barents Sea with, I would say, mixed success. And we are now active in testing the Western margin on the -- in the Barents Sea, which is, of course, where Johan Castberg and Goliat and Snøhvit and then ultimately you get into the so-called [ finger deep ] where Wisting is located. It will be interesting to see what turns out there. But so far, I think the expectations are somewhat modest. And then I think the last -- next round will be large tertiary exploration in the Barents Sea. And this is where it links with the [ tight ] stuff that we talked about, the Rondeslottet. The tertiary in the Barents Sea has almost always been a discovery case, but because of low permeability and low porosity and low density of infrastructure in the area, it's difficult to make economic. So that's basically the Barents Sea. And then Sverdrup swap and retrofit multilaterals. Well, of course, it is a little bit of a test as we're now entering into the first campaign of retrofit multilaterals. But it is a test that's based on very positive experiences from other fields. The question is, could we add more? Yes, absolutely. My expectation is that on the Johan Sverdrup field, you will be continually doing these kind of either side tracks or retrofit multilaterals to lift the drainage points towards the cross-border structure and towards as high up against the roof of the structure as you possibly can. And retrofit multilaterals is a very elegant way of doing that without having to drill the entire well in one new well. I don't think we have given direct estimates as to the breakdown of increased production per well, and I don't think we will either. But I think it's fair to say that these projects, they, with a good margin, delivers according to our investment criteria.

And then, Victoria, just to clarify, we don't necessarily see that there's room for a lot more MLTs in 2025, but definitely in 2026 and then onwards.

Thank you. Then the next question comes from Chris Wheaton from Stifel.

Two questions, if I may. Firstly, the production uptime really good this quarter, even above your usual excellent standards. Key standouts to me seem to be Valhall and Alvheim. Could you talk a bit more about what you've done, if anything, to change how those are performing because those historically have been patchy, but they seem to have improved significantly this quarter. Secondly, and picking up on Victoria's question on sort of the Barents. Is there any discussion at the Norwegian government level of potentially a different tax break for tight reservoirs? We've seen that in other tax jurisdictions globally. If there is that much additional resource to go for, it would seem to make sense to target that rather than continue to p*** money away in the Barents, which clearly is not working as the government would have hoped because we're not finding the resources. And when the resources are found, they're either too small or there are too much gas. And that's -- also, if I can throw in the third question. Could you talk a little bit more about the political risk in Norway because the -- as you commented in the results, the Supreme Court through the Scope 3 emissions question back to the Appeals Court, which perhaps was surprising because you would have thought Supreme Court would have just killed the question, just defined it. I wonder if you could talk about that because we live in an age where political risk seems to be much more in the tails than we ever could have imagined, say, 5 years ago.

Good. So let me touch on the production efficiency question first. Well, I think we -- have we done anything new? Not really. We basically continued doing what we're doing. And the main driver at this level is productivity and maintenance plans and making sure that we are in control over the vulnerabilities in the plant. Valhall has had a significant reduction in backlog on the maintenance activity, which I think you can actually now start to see in the production efficiency. Alvheim on the other side, has always been quite good, I would say, and now getting into extremely good standards. So I think this is basically just keep on doing what you're doing. I think we have a pretty good recipe, pretty good understanding of how to increase production efficiency. And this is about not making any revolution, but simply just working these numbers as we -- as best we can. Tax break for tight reservoirs, not a discussion that I've been a part of and not a discussion I've been aware of. I don't actually think it's needed. I think there's a lot to be done on the industry side to make these projects fly. And I think before we start discussing tax breaks for these type of projects, I think we, from an industry perspective, need to demonstrate that we're actually able to execute them. And then your question on political risk in Norway. Yes, I think the -- I wasn't too surprised, I must say, about the Supreme Court decision. What they did was basically to send the whole topic back to the Appeals Court, basically quoting that the Appeals Court had the competency to make a ruling, whereas in the Appeal Court ruling, they have pointed out a political decision and basically pointed it out of your...

On the courts.

On the courts, yes. So I wasn't actually too surprised that this was the case. And I don't think this is about politicizing or changing the courts. It's basically about whether or not the courts in Norway have the competency to make these decisions in terms of, what do you call it, preliminary injunctions, which is basically the case here. I don't think the risk is too high, to be honest. I think this is more a delineation of competency more than anything else. And then I think the last topic here is the 26th round, the decision in the Parliament about, well, now it seems to be a majority of -- in favor of a 26th round in Norway, which is again on the other side, right, where you're actually seeing oil and gas coming back into fashion. And now it seems that we will have a 26th round in Norway after quite a few years without these numbered rounds. So it's a bit of a balanced picture. On the totality, if you go into the helicopter and look at Norway, it's actually extremely stable compared to a lot of other volatilities that are happening in the world as we speak.

No, I would agree on the stability point. If you did have to -- if the Appeals Court did say you had to put Scope 3 emissions into -- or retrofit Scope 3 emissions into your production approvals, would that cause any significant delays? As you can see in the U.K., what we've seen with the ruling there from the court to do that, it's caused about a 9- to 12-month delay in the albeit limited amount of activity that's going on in the U.K. North Sea because of windfall tax, but it's still caused a delay. Would it cause you an impact?

We have already conducted that additional consequence assessment and it's been sent to the ministry in the case that there is a change in regulation, and we would need to execute on that. So we're trying to be a little bit ahead of the curve.

Ahead of the curve, as always.

Thank you, Chris. Next question comes from Steffen Evjen from DNB.

One question on Edvard Grieg for me. It seems production has stabilized now following a sharp decline over the past years, then you have 2 infill wells coming up this summer. Could you provide some color on the expectations for those wells? Could we see some incremental volumes here? Or is it just keeping production stable from Grieg?

So Steffen, by incremental volumes, you mean increased production?

Yes.

Okay. Yes. I mean, it's actually not a big surprise to us this behavior on Edvard Grieg and now it's actually pretty much according to what we've been modeled so far. And we've seen this, of course, on many fields in the past, right, where you have a sharp decline as you go off plateau. And then as you implement measures to stop decline, you eventually get to a flatter level and then you start drilling infill wells and you start this, I would call it, sawtooth profile again, right? The production goes up and then you drill a couple of wells and then it goes up again and drill a couple of more wells and you keep on doing that. This is basically the story of Alvheim for many, many years now and we're doing the same now on Edvard Grieg Ivar Aasen. So of course, we wouldn't drill infill wells if we didn't believe that, that would have a significant incremental impact on the Edvard Grieg rig, both reserves and production.

All right. Then next question, not the last one, is from Mark Wilson, the one and only, from Jefferies.

Just a couple of questions. First on your Rondeslottet. Obviously, a lot of discussion about that. But can I ask if you're doing anything specifically different on this well because it's a tight reservoir? Are you actually doing some fracking? And so what does success look like? That's the first one. And then the second one, very interesting to see you doing these 5 exploration wells in the Yggdrasil complex around Frigg. I take it that the FID of Beta/Epsilon would allow for inclusion of the success case in those exploration wells. Those are my questions.

So if you by fracking at Rondeslottet mean that we are carrying out the conventional fracking job, we are not. We are going to do, you call it mini fracs basically from the rig. The idea is to get a good understanding of the rock mechanic properties. Then we are running a specialized suit of, call it, reservoir assessment tools specifically designed for this well, and I don't really want to go into too specific details because we believe that this is a bit of the secret sauce around these kinds of assessments. And then we are also carrying out production tests and flow tests utilizing also specialized equipment. So I think the main topic around Rondeslottet is actually one of reservoir assessment rather than one of exploration. When it comes to the exploration wells on Yggdrasil. I think it's fair to say that in the planning of Yggdrasil, we always assume that this area will be prospective. So that means that every template has a tieback potential, so-called dovetail. So as we're now placing down the template for Yggdrasil, that obviously has capabilities of building infrastructure further west, if needed. And if we are finding -- if we're really successful and we find really high volumes, there are extra tiebacks, J tubes at the main host Hugin A if we want to put down a separate infrastructure in that case. So the whole Hugin A concept is really built for ease of tie-in of additional reservoirs.

Thank you. Okay. We have one final question today coming from Matt Smith from Bank of America.

Just one question left from me. I wanted to come on to Johan Sverdrup and expectations for production there and less about Phase 3 and the multilateral campaign coming up. But just how has performance on the existing wells and the existing sort of reservoir evolved since we last heard from you? Once upon a time, we were talking about water coning. How has that sort of situation evolved? How does that feed into your latest expectation on the plateau?

Thanks, Matt. And since this is the last question, I'll let you have the last word, David.

Okay. Thank you for that, Karl. So performance on Sverdrup has been excellent. I think the reservoir has performed in accordance with our expectations since last we talked, Matt. So what we're seeing is that production efficiency is being maintained at a very high level. And then also we are seeing some tapering off of the water. And you can see that from the numbers from the ministry as well. So I think we are very optimistic on the performance of Sverdrup going forward. And in combination with the MLTs and Phase 3, I mean there's a lot of good things ahead on Sverdrup.

I think that, Kjetil, was the end of the Q&A round?

It was.

That means it's time for me to close. So thank you so much for following this first quarter presentation from Aker BP. And I wish you a good and safe day and rest of the week.