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 Tønne, before we open for questions. 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 two to three 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 four key themes. The first were our 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 continue to build on this foundation. A good example is the five-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 our 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. 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. We remain firmly on track. Since the strategy update, we have also made two new discoveries, and we have several exciting exploration wells coming up in the months ahead. 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 equivalent per day, significantly exceeding our full-year guidance of 390,000-420,000 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. Overall, our current forecast suggests that we will end up within the full-year guidance range. Production costs for the quarter were $6.50 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 continue to rank among the companies with the lowest CO2 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 emission strategy. We are working systematically to eliminate avoidable emissions across the portfolio, and our plan to offset residual emissions from 2030 through 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 cost, an 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 two new wells completed and brought online so far this year, bringing the total number of production wells to 41. A four-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 III project, which includes two new subsea templates and eight 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. To briefly recap, the dark blue area represents our current business plan, including production from existing fields, ongoing field developments, and mature non-sanctioned projects such as East Frigg and Johan Sverdrup Phase III, 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 strengthens 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 four 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 three 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. To confirm, we are on track to deliver these projects 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 the first oil and gas planned for 2027. 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 Vanguard. 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 to around 700 million barrels. We see 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 five separate prospects along the same play that we proved with the East Frigg discovery in 2023. The combined pre-drill resource estimate for these targets is in the range of 40-135 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. While we are on the topic of exploration, we have an ambitious program lined up for 2025, with plans to drill 15-20 wells. Of the six completed so far, two have resulted in commercial discoveries. The first one was called Tjuchem, 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 38-74 million barrels of oil equivalent. 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 Eve prospect in the Skarv area. The main target yielded a minor oil discovery estimated at approximately 5 million barrels. 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. 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 through 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. 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 hold a substantial volume of oil and gas, and Aker BP aims to play a leading role in unlocking this major untapped potential. Rondeslåtte is an important step in that direction. While we certainly hope that this well will provide valuable answers, it is realistic to expect that 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 to Rondeslottet in particular and to tight oil opportunities across the NCS in general in the years to come. Good morning. As Karl had 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. 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 equivalent 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 underlifts. On the cost side, operating cost 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 to 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 $1.1 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 two to three years. We also recorded $189 million in impairments 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, is 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 remains stable at 0.3 times 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 Colin 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 remains 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 75-100% of planned NOK expenditures for the next three 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%-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 1.5 times leverage threshold in most scenarios, and way below the bank covenant of 3.5 times. Even in a prolonged $50 oil price environment, we only see a brief exceedance above 1.5 times, 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. For 2025, we plan to distribute a total dividend of $2.52 per share, paid in four quarterly installments of $0.63. Let me also briefly comment on our projected cash tax payments for 2025. As usual, we paid one tax installment in the first quarter, and two 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 a 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 equivalent 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-$420 as a fair estimate, but with Q1 now de-risked. Production cost 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 mid-range 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-$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. 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 a final investment decision for Johan Sverdrup Phase III and East Frigg. We have made two 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. As usual, to participate, please use the Teams link provided on the web page. If you prefer to listen only, please stay tuned, and we'll resume in just one minute. Thank you for listening in, and welcome back after that short break. We'll start with the Q&A session. As usual, Kjetil Bakken, our eminent Head of IR, is running the show. Kjetil, who's the first to ask questions? Yes, the first question today comes from Vidar Lyngvær of Danske Bank. Please go ahead, Vidar. Line is open. Thank you so much. 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 decommissioning, 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-$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. 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. This is why we have maintained our guidance. We think that that is a good assessment of where CapEx will end up this year. Of course, if we had 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. Thank you for the color, Karl. I could 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 the south of Europe? I think that's a little bit of a, I think there's a lot of opinions around that topic. From an Aker BP perspective, there are two main drivers for electrification and particularly usage from power from shore. The first one is obviously to reduce the greenhouse gas emissions intensity. I think the largely overlooked benefit is the fact that you 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 restrictions when it comes to transfer capacity. Power prices might be higher. There might be other install bases that do not lend itself to electrification the way the Norwegian Continental Shelf will. I think that you will find many opinions on that depending on where you are on this planet. Brilliant. Thank you for the color, Karl. I will queue. All right. The next question comes from Sasi Chilukuru from Morgan Stanley. Please go ahead, Sasi. The line is open. Hi, good morning. Thanks for taking my questions. Add two, 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 1.5 times 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 spent for those individual wells? Thank you, Sasi. I think I'll leave the financial flexibility question to you, David. Yeah, no, absolutely. You might be a bit disappointed if I didn't do that. Yeah, yeah, no, that's true. That's true. I think in terms of financial flexibility, you pointed to it, Sasi, right? We have prepared for volatile times. That's been part of the strategy of the company ever since 2014. We have low leverage, no material debt maturities before 2027. We have high financial capacity, $4.3 billion in cash on account and an un-drawn RCF. 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 we're currently ongoing, of course, there's a lot of flexibility in the sense that these are highly profitable projects. Very low breakevens, sanctioned between $35 and $40. Now that we have progressed projects leaving a lot of CapEx behind us, the breakevens of the projects obviously point forward, goes down. When these projects come on stream, we typically talk about the payback time of one to two years. Looking ahead in time, of course, there is flexibility around what do we sanction going forward. That is something that is further ahead of us in time. I think the key message here is that we are prepared for market volatility and we continue to progress as planned. On exploration, I appreciate the question. There are three major changes from the exploration list or list of wells that we presented in February. First, we have converted what we had as contingent slots into no-name slots. There are two additional wells that you probably will not see on the February list that you can see now in the Q1 list. Two, we have split out the exploration targets 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. 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. That is why we have ended up now with basically the same cost estimate. As you correctly point out, we have converted two slots into name slots and added one Well. Good catch. Thanks. All right. The next caller is Teodor Sveen- Nielsen from SpareBank 1 Markets. Please go ahead, Theodor. Good morning. Congrats on a strong quarter. A few questions for me. First, on slide seven, you talk about M&A as one 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? If you could provide any specific numbers, that would be useful. 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? Thanks. Yeah. You referred to slide seven. Yeah. 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. Obviously, this is now a buyer's market or a seller's market, sorry. There is a lot of activity, but the prices right now are not necessarily where we are interested in. That being said, we, and I think I say this all the time, there has not been a day I have been CEO of Aker BP, we have not had at least one M&A project running, and that is still the case. Maintenance, two major maintenance activities this year. The first one is in Q2 on Valhall, and then we have another activity as we approach September. 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. I'll come back to that as we approach Q2 and the actual results. Your final question was regarding CapEx investments and possible scale backs. I think my view on that, and this is basically talking about Aker BP and then 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. 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 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. You kind of lose on both ends, right? You have to make sure that as you are scaling these projects, and I do not have the details of what the different companies are doing, that this is actually worth the risk and cost of changing rather than executing. Thank you. That is clear. Just on the first question on M&A again, did you say that you still believe it is a seller's market on NCS? Right now, I think there is an influx of companies that want to participate on the NCS. Yes. Okay. Thank you. That is all from me. All right. The next question comes from John Olaisen from ABG. Please go ahead, John. Hey, good morning. Thanks. Good morning, and thanks for taking my question. David, on your slide 22, you mentioned that $50 is like the stress test where you see that you get it slightly above your own targets in terms of over-leverage. If you're going to say one number, do I interpret you correctly when I say that $50 is the level where above $50 our current dividend should be sustainable for the foreseeable future? If you're going to give a $1, like a one oil price level? One exact oil price. I've said this in the past, and I'll say it again. Our ambition is to grow the dividend by a minimum of 5% per year if the oil price is above $40. 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. That's where we are illustrating. Even in such a scenario, leverage ratio will only exceed 1.5 times net debt to EBITDA for a short period of time before deleveraging. The ambition of increasing the dividend goes also below that oil price level. The ambition to increase is 5%. Could you remind me, is that until 2027, or is it beyond 2027? Yeah. 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. That is as far as we have talked about that. Thank you. My second question goes to Karl. I appreciate that investing now, when the oil price is low, is good because you get the production when the oil price is higher. I guess you have some production wells that 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? Have you seen any considerations like that where you decide that it's better to hold now, hold on and wait a little bit and produce a little bit less now and save it for better times? Yes. Thanks, John. I'm actually quite poor in predicting the oil prices. I think the starting point is I wouldn't know exactly 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 up operational efficiency, we increase our performance is the way to actually execute it. 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 efficient activities around on a pretty complicated plan because I had an idea of when the oil price would change. 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 it to what the breakeven of what the type of projects we invest in are. If you look at the full project portfolio of Aker BP, right, at $65 spent, we have over 25% IRR across the portfolio. We are creating a lot of value by investing in this price environment as well. The Wells you're talking about are even better, right? The Wells where you have a lot of flexibility are basically IRR infill wells, which quite often have even better economy than the full-scale lifecycle projects. Thanks a lot. Good to hear. Good luck going forward. Thank you, guys. The next caller is James Carmichael from Berenberg. Please go ahead, James. Line is open. Hi. Morning, guys. Thanks for taking the questions. Just a couple of quick ones. Just interested in the sort of tight reservoir expertise that you describe, and 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, Ronda's slot is a big one, but are there sort of other areas that you're looking at? The current asset base. Just a quick second one. Could you just maybe remind us on the process or timing for the redetermination of the Johan Sverdrup review? Yeah. When it comes to tight reservoir, one of the characteristics with tight reservoir is relatively high STOIIP, right? So the actual implied volumes are pretty high. Two examples maybe. Ronda's slot, which is maybe in the range of $1 billion-$1.5 billion in terms of oil in place, and then Mjølnir, which is the horizon above the original Valhall reservoir, which is another $1 billion. You are actually talking about pretty big accumulations from an in-place perspective, right, which makes this attractive. The price of actually cracking this nut, so to speak, is quite high. Why it hasn't been done before? The complexity is also quite high, and there is a lot of technology and expertise that needs to go into this to make sure that we are creating economic projects out of these tight projects. We do believe, however, that as you are progressing the development on a region continental shelf, tight oil, high pressure, high temperature, and call it small tiebacks will be a large part of the remaining resource base. We are focusing on developing expertise within all of these three areas. Small tiebacks, we've been doing quite a lot of on the project so far in Aker BP. Fenris is the asset test of our high-pressure high-temperature capabilities, and that seems to be going quite well. 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 Ronda's slot, which I just spotted. Your second question was on redetermination. Redetermination, yeah. 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 communicatable. Okay. Thanks, Karl. Yes. Next question comes from Victoria McCulloch from RBC. Please go ahead, Victoria. Thanks very much for your time today. 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 a bit 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? On Johan Sverdrup, can you give any context on the upside that's being achieved from retrofitting the multilaterals? Is there any chance that more of these could be added to the schedule this year? Thanks very much. Yep. Let's talk about the Barents Sea first. Thank you for your questions. I think when it comes to the 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. We are now active in testing the western margin in the Barents Sea, which is, of course, where you are on 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. I think the last next round will be large tertiary exploration in the Barents Sea. This is where it links with the tight stuff that we talked about. 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. That is basically the Barents Sea. Sverdrup and retrofit multilaterals, 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? Yeah, absolutely. My expectation is that on the Johan Sverdrup field, you will be continually doing these kinds of either side tracks or retrofit multilaterals to lift the drainage points towards the crest of the structure and towards as high up against the roof of the structure as you possibly can. Retrofit multilaterals is a very elegant way of doing that without having to drill the entire well in one new well. I do not think we have given direct estimates as to the breakdown of increased production per well, and I do not think we will either. I think it is fair to say that these projects, they with a good margin deliver according to our investment criteria. Victoria, just to clarify, we do not necessarily see that there is room for a lot more MLTs in 2025, but definitely in 2026 and onwards. Super. Thanks very much. Appreciate that. Thank you. The next question comes from Chris Wheaton from Stifel. Please go ahead, Chris. Thank you very much, gentlemen. Good morning. Two questions, if I may. Firstly, production uptime really good this quarter, even above your usual excellent standards. Key standouts for me seem to be Valhall and Alfheim. 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 the Barents, is there any discussion at 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 piss money away in the Barents, which clearly is not working as the government would have hoped because they're not finding the resources, and when the resources are found, they're either too small or they're too much gas. May I also, if I can throw in a third question, could you talk a little bit more about the political risk in Norway? Because as you comment in the results, the Supreme Court threw the scope three emissions question back to the appeals court, which perhaps was surprising because you would have thought the 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, five years ago. Thank you. Good. Let me touch on the production efficiency question first. I think we have we done anything new? Not really. We basically continue doing what we're doing. The main driver at this level is productivity in 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. Alfheim, on the other side, has always been quite good, I would say, and now getting into extremely good standards. 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. This is about not making any revolutions, but simply just working these numbers 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 is a lot to be done on the industry side to make these projects fly. 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. Your question on political risk in Norway, yeah, I think 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 at a political decision and basically pointed it out of the courts. Out of the courts, yeah. I wasn't actually too surprised that this was the case. I do not think this is about politicizing or changing the courts. It is basically about whether or not the courts in Norway have the competency to make these decisions in terms of, yeah, what do you call it? Preliminary junctions, which is basically the case here. I do not think the risk is too high, to be honest. I think this is more a delineation of competency more than anything else. I think the last topic here is the 26th round, the decision in the parliament about where it now seems to be a majority in favor of a 26th round in Norway, which is, again, on the other side, right, where you are actually seeing oil and gas coming back into fashion. Now it seems that we will have a 26th round in Norway after quite a few years without these numbered rounds. 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 three emissions into or retrofit scope three 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 9-12 month delay in the limited amount of activity that's going on in the U.K. North Sea because of windfall attacks. It still caused the 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. We are trying to be a little bit ahead of the curve. Ahead of the curve, as always. Thanks very much indeed. Thank you, Chris. Next question comes from Steffen Evjen from DNB. Please go ahead, Steffen. Good morning. One question on Edvard Grieg for me. It seems production has stabilized now following a sharp decline over the past years. You have two 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? Thanks. Steffen, by incremental volumes, you mean increased production? Yes. Okay. Yeah. I mean, it's actually not a big surprise to us, this behavior on Edvard Grieg. It's actually pretty much according to what we've been modeled so far. We've seen these, of course, on many fields in the past, right, where you have a sharp decline as you go off plateau. As you implement measures to stop decline, you eventually get to a flatter level, and you start drilling infill wells, and you start these, I'll 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 you 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 and Ivar Aasen. 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 both reserves and production. Okay, that's clear. Thanks. All for me. All right. Next question, not the last one, is from Mark Wilson, the one and only from Jefferies. Thank you very much. Good morning. Just a couple of questions. First one, 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? What does success look like? That's the first one. The second one, very interesting to see you doing these five 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. Thank you. Those are my questions. Yeah. If you buy fracking at Rondeslotte, 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. We are running a specialized suite of, call it, the reservoir assessment tools specifically designed for this well. I do not really want to go into too specific details because we believe that this is a bit of the secret, this is a bit of the secret sauce around these kinds of assessments. We are also carrying out production tests and flow tests utilizing also specialized equipment. 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. That means that every template has a tieback potential, a so-called dovetail. As we're now placing down a template for Yggdrasil, that obviously has capabilities of building infrastructure further west if needed. If we're 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. The whole Hugin concept is really built for ease of tie-in of additional resource. Okay. Thank you very much. We'll hand it over back to the one and only Aker BP. Thank you. Okay. We have one final question today coming from Matt Smith from Bank of America. Hi, good morning, guys. Just one question left from me. And that was, I wanted to come on to Johan Sverdrup and expectations for production there and less about phase three 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, and 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. What we're seeing is that production efficiency is being maintained at a very high level. We are also seeing some tapering off of the water. You can see that from the numbers from the ministry as well. I think we are very optimistic on the performance on Sverdrup going forward. In combination with the LMLTs and phase three, I think there's a lot of good things ahead on Sverdrup. I think that, gentlemen, was the end of the Q&A round. It was. That means it's time for me to close. Thank you so much for following this first quarter presentation from Aker BP. I wish you a good and safe day and rest of the week.