Good morning and welcome to Aker BP's presentation of the fourth quarter and full year of 2024 results, which includes our annual strategy update, and as usual, CFO David Tønne and I will take you through the presentation, followed by a Q&A session. Let's begin with a brief overview of today's highlights. Aker BP delivered outstanding performance in both the fourth quarter and throughout 2024, with industry-leading efficiency, low production cost, and low emissions. Production reached the high end of our guided range, reflecting the strength of our operations. Our project execution remains on track, with all major developments progressing as planned, and importantly, our total CAPEX estimate for the project portfolio is still unchanged. Looking ahead, we have a clear strategy to sustain production above 500,000 barrels per day beyond 2030, with ambitions to grow even further. A key driver for this growth is Aker BP's 2 billion barrel opportunity, reflecting the significant upside in and around our existing assets. One example is Yggdrasil, where we have increased our resource ambition to more than a billion barrels. Another is Johan Sverdrup, where the operator has increased the recovery ambition to 75%. With a strong financial position and outlook, we remain committed to creating value for shareholders, including a 5% increase in dividends for 2025. Before handing over to David, I want to take a moment to reflect on Aker BP's core strengths and what we mean when we say that Aker BP is the E&P company of the future. The oil and gas industry is undergoing rapid evolution, fueled by technological innovations and new business models. However, in many ways, it has been slow to adapt, with much of the work still being carried out using traditional methods. Aker BP has been on a transformation journey over the past decade to build an E&P company that is future-fit. We have developed distinct capabilities that set us apart. We have a strong performance culture that drives execution excellence. We have well-established alliance models that foster collaboration across the value chain. And importantly, we have a leading position in digitalization, transforming the way we work. And with our world-class asset base, we are delivering industry-leading performance. The track record speaks for itself, and I want to take this opportunity to thank the entire Aker BP team for their outstanding work, both in 2024 and the years before. And then finally, as mentioned, we have a clear strategy to sustain production above 500,000 barrels per day beyond 2030 and aim for further growth. With our capabilities, assets, and tools, we are ideally positioned to drive profitable growth on the NCS into the 2030s. Finally, our financial framework is designed to maximize value creation through profitable growth and strong shareholder returns, something I'm pretty sure David will cover in more detail. And with that, David, let's take a closer look at the 2024 fourth quarter and full year results. 2024 was a year of exceptional operational performance, laying a solid foundation for continued delivery of our value creation plan. Sustained high production and low operating costs, in combination with a relatively stable commodity price environment, translated into a record high operating cash flow of $6.4 billion. Our development projects progressed according to plan, and Karl will come back to this in more detail in the strategy update section. We grew distributions to shareholders by 9% year over year, paying $2.4 per share in dividends, and we have proactively worked to further fortify our financial position. Among other things, we refinanced most of our short-term maturities with longer-dated debt, and in the fourth quarter, we have successfully issued our first 30-year U.S. dollar bond. In short, we leave 2024 stronger than ever, focused on maximizing long-term value to shareholders. And for us, this always starts with operations. Our 2024 operational summary shows how we continued to deliver strong performance by sustaining production, reducing costs, and advancing the decarbonization of our business. Total production ended at 439,000 barrels of oil equivalents per day, with an average production efficiency of 93%. We finished the year on a high note with Q4 production of 449,000 barrels per day, driven by outstanding contributions from several key assets. Most notably, Johan Sverdrup maintained plateau production throughout the year and achieved a new all-time high annual output. Alvheim and Valhall also deserve recognition, with the Tyrving project coming on stream, boosting production in the Alvheim area. At Valhall, the team maintained a production efficiency above 95% in the fourth quarter, a level not seen in many years on this asset. The reduction in production from 2023 to 2024 is mainly driven by natural decline on Edvard Grieg, where we now see that the decline rate has really tapered off. Production cost remained flat year over year at $6.2 per barrel, which is lower than expected, driven by good cost control and a weakening of the Norwegian krone. Our GHG intensity ended at 2.6 kilos per barrel of oil equivalents produced, continuing to trend down from already industry-leading levels. The strong operational performance also translated well into our financial results. Earnings ended at $2.9 per share, up from $2.1 in 2023. More important, we achieved a record high cash flow from operations after tax of $10.2 per share, providing a solid foundation for our dividends paid of $2.4 and in addition, covering most of our growth investments. If we adjust the 2024 cash flows for phasing of cash taxes, as the taxes paid in the first half of 2024 was for the year 2023, the underlying cash generated in 2024 was almost $1.2 billion higher. This gives an adjusted free cash flow after investments and financing costs more than covering our dividends paid. Through the year, we also strengthened our liquidity position, and we ended the year with a conservative leverage ratio just below 0.3 times net debt to EBITDAX. Zooming then in on a few key points from the fourth quarter results specifically. Production in the fourth quarter was, as mentioned, 449,000 barrels of oil equivalents per day. But as we had 10,000 barrels of underlift, the net sold volumes ended at 439. Realized hydrocarbon price was $75 per barrel of oil equivalents in the quarter, with realized oil prices remaining close to Brent. We achieved very low operational cost at $5.7 per barrel produced in the quarter, compared to $6.6 in Q3. This was driven by a reduction in maintenance cost in combination with a ramp-up in production. As already highlighted, cash flow from operations was record high in 2024, and when examining the separate quarters, there are some differences worth noting. Before tax payments and changes in working capital, cash flow remained fairly stable throughout the year. However, with two tax installments in the second and fourth quarter, these quarters had lower cash generation. In the fourth quarter, we also had a negative effect of the reversal of working capital from Q3 back to a more normalized level, so to get a better view of the actual underlying cash generation, I recommend looking at the third and the fourth quarter in combination. Investments in the quarter remained stable and in line with our overall plan. The combination of two tax installments and the increase in working capital left us with a negative free cash flow of $304 million in the quarter, or minus $0.48 per share. On a full year basis, we generated over $1.1 billion in free cash flow, and combined with two successful bond issuances, we strengthened our total cash position to $4.1 billion, an increase of over $700 million since the end of 2023. In combination with our undrawn bank facilities of $3.4 billion, the total available liquidity at the end of the year was $7.5 billion. To round off, let me comment on how our 2024 deliveries compared against our guidance to the market throughout the year. We started 2024 with a production guidance of 410-440, with the message that the key drivers of where we would end up were dependent on the ability to maintain the high production on Johan Sverdrup and the absence of any major unplanned production stoppages. With strong performance as we progressed through the year, we were able to lift the lower end of the range at both our Q2 and Q3 presentations, ending with the most recent guidance of 430-440,000 barrels per day. Johan Sverdrup delivered stable production throughout the year, and total Aker BP production for 2024 ended at the high end of the range after a very strong fourth quarter. Production cost was originally guided close to $7 per barrel for 2024, and we ended at $6.2. The drivers for outperformance are well known to those of you who follow our quarterly presentations. Cost discipline, lower electricity costs than planned, a weakening of the Norwegian krone, and strong production have all contributed positively. CAPEX in 2024 ended at $4.8 billion, close to the guidance of around $5 billion. Considering the weakening of the Norwegian krone and the general uncertainty around phasing of activity around year end, this is pretty much spot on our expectations. Exploration and abandonment spend also ended at guidance of close to $500 million and $250 million, respectively. Now, with a strong 2024 behind us, the stage is set for a deeper dive into our updated plans for the future. Thank you, David. My key takeaway is that we are continuing to deliver strong operational performance and solid project execution. But more than that, it is a testament to our ability to create value, not just today, but well into the future. As I mentioned in my opening remarks, I think Aker BP is ideally positioned to drive profitable growth on the NCS well into the 2030s. And in a few moments, I'll show you exactly why. But before we get into that, let's take a step back. Why does this even matter? Will Norwegian oil and gas be relevant in the 2030s? Now, we really think so. And to put this into perspective, I've invited Aker BP's Chief Economist, Torbjørn Kjus, to join me. And Torbjørn, you have spent your entire career analyzing the oil and gas market and energy markets. Where are we heading? I guess that's the really big question, isn't it? So will Norwegian oil and gas still be relevant after 2030? The short answer is yes, it will. But let's take a closer look at the numbers. Now, let's start with the demand side. Fossil fuels still cover about 80% of global energy demand. That's unchanged over the past 30 years, approximately. In other words, the world has not seen an energy transition yet. It's only seen an energy addition. All credible scenarios, including those from the International Energy Agency, show that oil and gas will remain essential for the global energy mix for decades. The main reason is that 80% of the global population lives in the developing world, where both population and economic growth continue to rise. While renewable energy sources like wind and solar are expanding rapidly, they still cover less than half of the growth in global energy demand. The energy transition will take time, and phasing out fossil fuels too soon would lead to energy shortages, extreme prices, economic instability, and potential social unrest. A sustainable energy system must balance four core needs, adding one more dimension to the traditional energy trilemma. It's security of supply, its affordability for consumers, its environmental and climate sustainability, and the fourth thing is economic viability of investments into this new energy system. Over time, it probably needs to be without government subsidies. Achieving this balance has proven challenging. An unbalanced approach to energy policy can lead to unintended consequences, such as underinvestment in oil and gas before sufficient alternatives are in place. The key challenge is not choosing between fossil fuels and renewables, but ensuring that the energy system evolves in an orderly, balanced, and resilient way. This means continuing to produce oil and gas efficiently while reducing emissions and expanding cleaner energy sources in parallel. A good example of the challenge it has played out in the European weather-dependent energy system. When the wind is not blowing and the sun is not shining, power generation from natural gas and coal must ramp up quickly to avoid failures. Sometimes this requires extremely high prices to bring the last power plants online. Europe, our closest market, has an ambitious energy transition agenda but faces challenges due to low self-sufficiency in natural gas, 40% dependency, and oil only 20% self-sufficiency. Despite consuming 13.5 million barrels per day of oil, Europe produces very little itself. Norway, a key supplier, produces 2 million barrels per day. A study by Wood Mackenzie indicates Europe will remain a net importer of oil and gas even with strict climate goals. Without Norwegian oil, other nations would need to fill the gap, increasing global CO2 emissions. Norwegian oil and gas have significantly lower emissions compared to other sources, making them crucial for Europe's energy needs. The NCS has been a major oil and gas producer for 50 years. However, according to the latest resource report from the Norwegian Offshore Directorate, up to 40 billion barrels remain to be produced, contingent on exploration success, technological advancements, and investment activity. To unlock this full potential, we need to increase exploration efforts and enhance our ability to develop small fields, HPHT discoveries, and tight oil reservoirs. Moving forward, competence, efficiency, and technology will be even more crucial. In conclusion, there are huge oil and gas resources yet to be produced in Norway, and there will be a market for this oil and gas. It's up to the oil companies to seize the opportunities available. Thank you, Torbjørn. I really couldn't agree more. The case for Norwegian oil and gas remains strong, and Aker BP is well positioned to capitalize on it. Competence, efficiency, and technology, that is exactly what defines us. Earlier, I briefly touched on Aker BP's transformational journey over the past decade towards becoming a future-fit company. We firmly believe that our distinct capabilities will be the key to our success in the years ahead. We've built a performance-driven culture that drives execution excellence. We have established a strong alliance model to foster collaboration with our suppliers, and we lead the way in digital transformation, driving efficiency and innovation across the industry. But let's start with the one thing that all great companies have in common: people. I believe we have some of the most talented and high-performing professionals in the industry, people who are experts in their field and deeply committed to driving our company forward. What sets Aker BP apart is our relentless focus on continuous improvement. We are obsessed with finding better, smarter, and more efficient ways to operate, whether it's in drilling, project execution, or digitalization. But talent and ambition alone are not enough. Our culture makes a real difference. We have a results-driven mindset combined with a strong one-team spirit, where collaboration and shared success define how we work. I vividly recall standing on one of our platforms last year, speaking to an engineer and a technician who have just solved a particularly tricky challenge. Their backgrounds were different, their expertise unique, but what really struck me was how seamlessly they worked together, challenging, listening, refining ideas, and solving the problems as a team. No silos, no egos, just a shared drive for success. And that is what Aker BP culture is all about. It is this combination of exceptional people, a culture for improvement, and a result-driven mindset that is a key part of the capabilities we need as the E&P company of the future. To be the best at developing oil and gas resources, we must ensure that we are getting the best from our suppliers. When developing new fields, building platforms, or drilling wells, our suppliers play a critical role. And this is where the alliance model comes into play. The alliance model is built on collaboration. Aker BP and our key suppliers work together as one team, with shared goals, aligned incentives, and a focus on continuous improvement. We designed our alliance model to overcome the usual inefficiencies in the industry. By cutting complexity, improving accountability, and driving constant improvements, we can reduce both time and cost while maintaining the right quality. But the alliance model wasn't something we invented. We borrowed it from the automotive industry and adapted it to our needs. We launched our Subsea Alliance back in 2016, and the success of that initiative led us to expand the concept into drilling, fixed facilities, well interventions, modification, and a lot more. Our model is really simple and built on three key principles. Operational: early involvement, a structured learning process, and a manufacturing mindset is fundamental to operational excellence. Organizational: our one team integrated and accountable for everything they do. And then transactional: shared incentives, an open book, transparency, and pay for performance, not just for hours. The alliance model has driven down time and cost, improved predictability, and been a resounding success for us. But rather than hear me explain it further, let's hear it from John Evans, CEO of Subsea7. I'm pleased to share my thoughts on the strong partnership we've built with Aker BP and OneSubsea through the Subsea Alliance in Norway. The alliance model we've established is a true testament to the power of collaboration. By working closely, from concept selection to execution, we've fostered an environment of trust, transparency, and shared accountability. This has enabled us to deliver exceptional results, with numerous projects completed successfully and several others currently underway. What makes this partnership stand out is Aker BP's relationship and commitment. Aker BP has embraced a forward-looking, pioneering approach, ensuring that all. Enables us to discover more oil and gas, accelerate field developments, and optimize operations. With digitalization, we can create value where others might give up, expand our opportunities, and deliver superior returns on investment. Digitalization has been a strategic priority for us since 2016, and we played a key role in developing the data platform now known as Cognite Data Fusion, which enables a seamless flow of high-quality data across our business, from exploration to production. With the AI revolution underway, this positions us ahead of the curve. In short, we are once again future-fit. But to be concrete, let me give you some examples. As Torbjørn mentioned, reservoir developments on the NCS will become more complex in the years to come. Achieving the right development solution will require more interactions. This will mean that the timelines will need to be shorter and the quality higher. One of our key digital initiatives is Agile Asset Management, or AAM. We're developing this scalable platform together with Halliburton Landmark. It provides our engineers with instant access to and integration of vast datasets from geology, reservoir, and production planning, all in one place. Experts across disciplines can collaborate seamlessly, test concepts, and refine plans in real time. The result? Significant time savings, improved quality of concept selection decision, leading to even better field developments with higher returns. We are already leveraging parts of this platform to execute our current development projects more efficiently, and as we scale up its application, we will not only improve efficiency but also transform the way we develop oil and gas fields. Another key initiative we're rolling out in 2024 and 2025 is the Aize toolkit. Since 2022, we have worked with Aize to develop a tailored visualization solution that allows our onshore teams to plan and manage field operations remotely. We have already started using this solution across several assets, and it plays a vital role in preparing for efficient operations at Yggdrasil from 2027. Finally, in collaboration with Cognite, we have leveraged AI algorithms on the Cognite Information Graph to uncover new methods for performing complex fault-finding tasks such as root cause analysis. While testing is still ongoing, it appears that 70%-90% improvement in productivity is well within reach, and at the very least, this highlights how fundamentally important AI will be in an industrial setting. However, digitalization is not just about technology, software, and data. It's about delivering real value that enables us to do things better, faster, and cheaper. It's about making sure that we are future-fit, as these examples just demonstrate. We are well underway, and in 2025, we will scale our efforts even further. It is probably no big surprise, but operational excellence is extremely important for Aker BP. Needless to say, strong performance leads to strong results. And more importantly, strong performance is a must to stay competitive over time, which Aker BP definitely intends to do. Today, I will focus on a few key performance indicators that are essential in our financial results and our license to operate. The first is safety. It is clear that we have an obligation to protect our people. Moreover, we firmly believe that a safer workplace is a more efficient one. That is why safety is always our top priority, and even if every safety incident is thoroughly investigated to prevent reoccurrence. I am pleased that 2024 was another year of strong safety performance. However, given our high activity levels, both onshore and offshore, safety continues to be a key focus area across all our operations. Our focus on safety also directly supports production efficiency, which is our key measure of productivity across our oil and gas fields. Production efficiency in reality reflects capacity utilization, and as such, it's directly linked to returns on investment. We have consistently delivered strong performance, and I believe this success is driven by three key factors. The first is our relentless focus on continuous improvement. We systematically identify opportunities to optimize operations, reduce downtime, and enhance reliability. The second is our people. We have a highly competent workforce with a performance-driven mindset and a strong team culture, an army of problem solvers, as one observer once described us. The third factor is our digital architecture. Real-time data, advanced analytics, and digital tools allow us to closely monitor performance, make informed decisions, and act swiftly when needed. Our commitment to production efficiency has yielded tangible results in the form of increased production, higher margins per barrel, and accelerated cash flows. In the oil and gas industry, we have little control over the price of our product. So to drive margins, our focus must be on managing unit cost. At Aker BP, we view low unit cost as a competitive advantage, and we have made it a strategic priority. Last year, we once again achieved production cost of $6.2 per barrel, well below our target of $7 per barrel, reinforcing our industry-leading position. Now, several factors contribute to these strong results. High production efficiency ensures that we maximize output from our assets, while our focus on continuous improvement drives cost reductions across the business. From smarter maintenance strategies to optimized logistics, every initiative helps sustain our long and strong performance. Looking ahead, our long-term goal remains clear: to maintain production costs at or below $7 a barrel. By staying disciplined and continually challenging ourselves, we will strengthen Aker BP's position as one of the most cost-efficient operators in the industry. I probably don't need to explain why greenhouse emissions are important, but when we focus on the business side, it is clear that CO2 emissions carry a cost, and that cost is likely to increase over time. As a company with ambitions to grow into the 2030s and beyond, we believe that low emissions will be fundamental to our success. As you can see on this chart, Aker BP is extremely well positioned in this area. Over the past five years, we have reduced our emission intensity by more than 50%, down to roughly 2.6 kilograms per barrel in 2024, reaffirming our global leadership position in the industry. This strong development results from a long-term focus on electrification, energy efficiency, and innovation. Looking ahead, we remain committed to reducing our absolute emissions from our operations. New field developments will be electrified. We are exploring solutions for carbon capture and storage, and we are engaging with partners, suppliers, and policymakers to drive industry-wide improvements. By 2030, we aim to neutralize our remaining Scope 1 and 2 emissions with nature-based carbon capture. This is also all about ensuring that we are future-fit once again. Now, we've covered operational performance. Let's move to our assets, because this is where the magic happens. This is where ideas are transformed into profits, which can then be reinvested in new profitable projects or distributed to our shareholders. The better we operate and develop our assets, the more value we can create. Aker BP operates production hubs at Alvheim, Edvard Grieg, Ivar Aasen, Skarv, Valhall, and Ula, in addition to the future production hub at Yggdrasil. But we're also a significant partner in the giant Johan Sverdrup field, which in 2024 delivered around half of our production. Johan Sverdrup is one of the largest oil fields ever discovered in Norway, with original in-place volumes of nearly 4 billion barrels, following a highly successful development project delivered on time and well below budget. Production started in 2019, with phase two coming on stream in 2022. Through de-bottlenecking and optimization, production capacity has been increased to 755,000 barrels per day, 14% above the original design capacity. The field boasts ultra-low unit costs of around $2 per barrel and CO2 emissions of less than a kilo per barrel. Operational performance has been outstanding, with exceptionally high regularity, a testament to the quality of the facilities and the strong execution by Equinor, the operator. Our 2P reserves currently booked for Johan Sverdrup reflect an ultimate recovery factor of roughly 68%. Last week, Equinor, the operator, announced an ambition to push recovery to 75%. With 31.6% interest, this would add approximately 100 million barrels to our reserves. Johan Sverdrup has been consistently exceeding expectations, and 2024 was no exception. The field set a new production record and surpassed 1 billion barrels produced. This remarkable performance is driven by a uniquely productive reservoir, high facility uptime, and the exceptional work of Equinor, the operator. Looking into 2025 and based on current performance, the planned work production is expected to remain close to 2023 or 2024 levels. Now, in the first quarter, we are completing the final two wells from last year's drilling program. Later this year, we will drill four retrofit multilateral side tracks to existing wells to enhance drainage and to optimize production, helping sustain high output from the field. Beyond that, drilling at Johan Sverdrup will continue for years to come. We are already planning phase three, which will expand subsea infrastructure and improve access to remote parts of the reservoir. Additional infill wells, including more retrofit multilaterals, are also expected over time to further optimize recovery. In short, Johan Sverdrup is a world-class asset that continues to grow. With one billion barrels produced, it remains a young field with almost two billion barrels yet to come. For Aker BP, it's a cornerstone of our business, generating strong cash flow that supports profitable growth and attractive dividends. Apart from Johan Sverdrup, all our production comes from assets we operate ourselves. For over a decade, we have built deep expertise in developing, operating, and expanding our assets by focusing on operational efficiency, reservoir management, enhanced recovery methods, efficient project execution, drilling performance, and near-field exploration. Alvheim was our first operated asset, acquired from Marathon Oil in 2014. At the time, the field had been in production for six years, and production was declining. However, we saw significant upside potential and immediately set out to unlock it. The Alvheim area features a floating production unit producing from over 50 well branches covering more than 150 km of reservoir exposure. The key technical challenge was drilling long horizontal wells with high precision to access thin oil layers, something previously considered too complex. Our drilling and subsurface team rose to the challenge, developed world-class expertise, and delivered increasingly advanced wells with industry-leading efficiency. In parallel, we transformed the execution of subsea tiebacks. In the past, these projects had been delivered on time and on budget, but we saw little cost or time reduction. The learning curve was basically flat. Our answer was to establish what is now the Subsea Alliance, which quickly delivered impressive improvements with up to 50% reduction in execution time and cost. Beyond drilling and tiebacks, we pursued an active area strategy, leveraging advanced data acquisition and reservoir insights to expand Alvheim through licensing rounds, exploration, and acquisitions. This has enabled several successful satellite developments, most recently KEG and Tyrving. Both delivered ahead of schedule and below budget. As a result, total recoverable volumes from the Alvheim area have surpassed 750 million barrels. That is almost four times the original PDO estimate. But the success story is not just about resource growth. It is also about operational excellence. For eight consecutive years, Alvheim has maintained production efficiency between 95% and 99%, placing it in the top quartile of the North Sea fields. Now, this performance is a testament to our world-class facilities and the exceptional team driving Alvheim forward. The success of Alvheim serves both as an inspiration and a blueprint for how we operate our other assets. A great example is Skarv, originally developed by BP with a brand new FPSO. Production started in 2013. When we took over in October 2016, we immediately applied key learnings from Alvheim. One of our first moves was to fast-track the development of the Ivar Aasen discovery, submitting the PDO just 14 months later. By leveraging our Subsea Alliance, introducing more efficient development concepts, and deploying new technology, we succeeded in reducing the estimated break-even oil price from over $50 per barrel to under $35 per barrel. At the same time, we expanded our footprint around Skarv and launched an extensive exploration program. Since then, we have drilled 18 exploration wells in the area, resulting in 11 discoveries. The first wave of these discoveries is now being developed through the Skarv satellite project, with more exploration and tieback opportunities to follow in the years ahead. Another key area where we are applying the same strategy is Valhall, one of Norway's giant fields with more than 4 billion barrels originally in place. Since production started in 1982, around 1.1 billion barrels have been recovered, and our ambition is to reach 2 million barrels. We have already expanded Valhall with the successful delivery of the Flank West project and the redevelopment of Hod. We're now taking the next major step, the Valhall PWP-Fenris project, which will replace aging platforms, add new well capacity, and expand gas handling capabilities, unlocking even more value from the area. To achieve our ambitions, we are advancing on multiple fronts. We continue to improve well delivery by applying more efficient drilling techniques and stimulation methods to maximize productivity. The additional gas handling capacity being built will not only support Fenris, but could also position Valhall as a gas hub in the central NCS. Beyond the existing reservoirs, Valhall holds a massive untapped potential, a significant oil accumulation in the Miocene formations above the producing zones. Successfully unlocking this resource would be a game changer for Valhall's long-term future. In recognition of our efforts to enhance recovery at Valhall, we were honored with the 2024 IOR Award from the Norwegian Offshore Directorate, a testament to the innovative work being done to maximize value from this world-class asset. Valhall will remain a cornerstone of our production for decades to come. At the same time, its expanded infrastructure and strategic location make it an increasingly attractive hub for future oil and gas developments in the southern NCS. Following the Lundin acquisition, the Grieg-Aasen have also become a key hub where we can apply the Alvheim blueprint to drive further value. Edvard Grieg started production in 2015 and served as a hub for Ivar Aasen, which came on stream about a year later. Production from these fields has exceeded expectations. Plateau production lasted five years longer than planned, and total reserves have nearly doubled. This success is a result of both excellent reservoir performance and tieback of nearby discoveries. Since we took over Edvard Grieg in 2022, we have been operating these fields as a single organizational unit. The same year, we launched three new tieback projects: Hanz, Symra, and Solveig Phase II, to further enhance production from the area. Hanz was successfully completed and started production last year via Ivar Aasen. Symra and Solveig Phase II are tiebacks to Ivar Aasen and Edvard Grieg, respectively. Both projects are progressing as planned, with first oil targeted next year. Like our other hubs, we see significant potential for further resource growth in this area, both through improved recovery methods and future exploration. One particularly interesting opportunity in this area is the fractured basement, which is expected to hold several hundred million barrels of oil. Unlocking this potential could deliver substantial additional value in the years ahead. All these successful asset stories demonstrate how fields can grow over time with the right approach to area development. The key to unlocking this potential lies in efficient operations, securing the right acreage, leveraging advanced data and reservoir models, and executing projects in a highly competitive manner. At Yggdrasil, we are taking this to the next level. Even though the name comes from ancient Norse mythology, we still call it the field of the future. Yggdrasil is designed for a new area of oil and gas production. The field will operate with minimal staffing, and after the initial years of production, it will be periodically unmanned, remotely controlled from an integrated operations center in Stavanger. The project also represents a major step forward in low-emission operations. Yggdrasil will be powered by renewable electricity from shore, enabled by a 255 km high-voltage AC power cable, a technological leap for offshore power transmission. The development consists of Hugin, a central processing platform that will serve as a hub, several unmanned production platforms, and an extensive subsea production system. But Yggdrasil is more than just a new development. It is a groundbreaking project that sets new industry standards. The digital twin ecosystem will transform our operation, enabling predictive maintenance and real-time monitoring. Advanced condition monitoring will greatly reduce the need for on-site maintenance, while automated control sequences will optimize production with minimal human intervention. Additionally, an open control room environment will allow operators and engineers to proactively drive production optimization. In short, we have been preparing this field since we began our digitalization journey in 2016. Perhaps even more importantly on Yggdrasil, we have applied all the lessons learned from the other assets that I just briefly covered. Even before the production begins, we are already planning further expansion. A key design choice to support this strategy was the inclusion of ample additional well slots, making it easier and much more cost-effective to add infill wells and tie in future discoveries. Approximately half the well slots are actually available for such expansions. Yggdrasil has already been proving this upside potential. When we sanctioned the project in 2022, it was based on recoverable volumes of roughly 650 million barrels. In 2023, the East Frigg discovery increased this estimate to around 700 million barrels, and we see further potential in this area. Several exploration wells are being planned, including prospects beneath the old Frigg gas field, an area we were actually awarded just last month. Based on this upside potential, we have raised our resource ambition for Yggdrasil to over 1 billion barrels. The Yggdrasil development is progressing according to plan. Construction is well underway across all sites. Subsea infrastructure installation has started, and jacket installations and drilling of production wells will commence later this year. Instead of just talking about it, here's a glimpse of what we have achieved so far in 2024. Efficient project execution is absolutely essential for Aker BP, and our track record speaks for itself. Looking at our last 10 projects, all have been delivered on or ahead of schedule and 2% below budget on average. The projects have an impressive break-even price of below $30 per barrel on average, and based on actual oil and gas prices, achieved an IRR of above 40%. In 2024, we successfully completed the Tyrving project at tie-back to Alvheim nearly six months ahead of schedule. With this, we have successfully delivered all the Alvheim tie-backs sanctioned in 2022. Meanwhile, we continue to make strong progress on both Yggdrasil, as we've just seen, and our other major developments: Valhall PWP-Fenris, the Skarv satellite project, and the Utsira High project. These projects sanctioned in the fourth quarter of 2022 all remain on track for the first oil in 2026 and 2027. A critical phase in any project is the transition from engineering to construction, a stage where delays and cost overruns often occur. We have successfully navigated this challenge through detailed engineering and planning, combined with an advanced digital collaboration platform that allows us real-time information sharing across teams and locations. This has contributed to high quality and reduced waste. In 2024, we reached several key milestones. All assembly activities started as planned, and we performed several major offshore installation activities, including the Fenris jacket, multiple subsea templates, and many kilometers of subsea cables. We also successfully delivered the first HPHT well on Fenris, and most importantly, with around 20,000 people involved in our project, we have achieved all of this without any serious HSE incidents. Looking ahead, 2025 will be a pivotal year. Construction and assembly of topside modules will continue at full speed. Jackets will be installed offshore, and we will be drilling production wells across all projects. The momentum is strong, and we remain fully committed to delivering all these projects safely, efficiently, and on time. One of the big ticket items in oil and gas projects is drilling, typically accounting for 30%-50% of the total budget. By enhancing efficiency in well delivery, we can reduce both time and cost, ultimately improving returns on investment. Let's hear what our drilling team has to say about this. Drilling and Wells' ambition is to be the best and most attractive drilling and wells team in the world. And we do this by being first and best in what we do. Our most competitive advantage is our people, whom we truly believe are our most important asset. Working in alliances and being a front runner in digitalization is key to how we deliver day-to-day operations and our PDO scope. Simultaneously, we have a strong focus on improvement and transforming the way we work. We make decisions based on data. Our performance is closely monitored, and we consistently deliver top quartile wells compared to our competitors. Check this out. The East Frigg Epsilon was the longest horizontally drilled well on the Norwegian Continental Shelf. A key factor in this success was the competency our team has developed through collaboration, challenging so-called established truths, data-driven decisions, and optimization of well placement, or bold and experimenting, as we call it. Yggdrasil is an area development with 10 discoveries. Creating a new production hub and supplying production from 57 new wells demonstrates Aker BP and Drilling and Wells' boldness and grit. Through technology development and new methods, we will deliver the wells of tomorrow as a part of transforming Aker BP. For us in SLB, working in an alliance means that we are working closely together. We can improve together, but also pull in on the bigger muscle from SLB to really find solutions for the alliance. I am truly grateful to be part of this alliance, to work closely with Karl and his team, and the way their team and our team become one team. Focus around first the strategy, but every bit as important, the execution and delivery of those changes that make our alliance so successful. We have the opportunity to unlock new projects if we succeed with our transformative ambition. That's why we balance the duality by using the current runway of projects, setting a new standard, and driving transformative initiatives in parallel so that we can drill the wells after tomorrow. Our drilling team has really delivered outstanding results. Congratulations. Together with our alliance partner, Odfjell Drilling, Noble, Halliburton, and SLB, they have continually pushed boundaries of drilling efficiency with remarkable success. This chart shows benchmarking data for all wells drilled in Norway in 2023, highlighting Aker BP's strong performance. These are really impressive results and a strong indicator of our capability to continue delivering going forward. This chart summarizes many of the key points we have covered so far. It reaffirms the production profile through 2028, which we have shown before, and now extends the outlook by two more years. The dark blue area represents our current business plan, which includes our producing fields, ongoing projects, and mature non-sanctioned projects such as East Frigg and Johan Sverdrup phase 3, along with regular IOR activities. This outlook remains largely unchanged from last year, with production reaching around 525,000 barrels per day in 2028. Beyond 2028, the light blue wedges illustrate the potential to sustain production above 500,000 barrels per day for additional infill drilling and tiebacks of discoveries at our existing assets. Further growth into the next decade is also well within reach. With exploration success and potential M&A opportunities, we see a strong case for expanding our production outlook well beyond the current of today. This is our goal. We have the people, we have the suppliers, we have the assets, the digital ecosystem, the track record, and the capital to deliver on this ambition. And as I will now show, we have the oil and gas resources to support it. This chart illustrates our resource base. The foundation is our 2P reserves of nearly 1.6 billion barrels in existing fields. Above that, shown in blue, is what we call Aker BP's 2 billion barrel opportunity, built on three key pillars. The first pillar is increased oil recovery, which is about continuously developing our assets to maximize production. We are, for instance, drilling additional wells to unlock more reserves and extend field life, and we're optimizing flooding techniques to improve recovery rates and enhance reservoir performance. By leveraging advanced reservoir simulation and 4D seismic, we identify and extract left-behind oil pockets, ensuring that we make the most out of our existing resources, and at the same time, we are refining our reservoir management strategies for advanced monitoring and targeted interventions. As discussed earlier, we are an industry leader in drilling and completion, enabling us to drill high-efficiency production wells efficiently and cost-effectively. IOR is at the core of what we do, and we have a strong track record for applying technology and innovative reservoir management to maximize production from our assets. The second pillar is 2C resources or contingent resources, discoveries that have not yet been sanctioned for development. We have around 800 million barrels in this category. Nearly 500 of these are located in or around our existing production hubs and are currently being addressed as part of the overall development plans for each asset. Good examples include East Frigg and Johan Sverdrup S3. Another 200 million barrels are in discoveries likely to become new field developments. A prime example is Wisting in the Barents Sea, where we're progressing towards a concept selection this year. Another is Garantiana, which also holds significant potential for future development. The last roughly 100 million barrels are spread across a set of smaller discoveries where we're currently working on field development concepts and/or technological solutions. The third and potentially largest pillar is infrastructure-led exploration, ILX. By targeting resources that can be tied back to existing fields, we leverage spare capacity in these existing facilities, reduce unit costs, and extend the life of the host assets. ILX developments typically have shorter lead time and lower capital requirements than standalone projects, making them highly attractive. A great example of ILX success is the East Frigg discovery at Yggdrasil. At the top of the chart, we find standalone discoveries and mergers and acquisitions. Let's cover them in sequence. As highlighted earlier, there is still a substantial undiscovered resource base on the Norwegian Continental Shelf. With the second-largest license portfolio on the shelf, Aker BP is ideally positioned to capitalize on this potential. Our exploration strategy is clear: maintain high and consistent activity levels while systematically exploring the remaining potential on the NCS. This involves robust idea generation, active participation in licensing rounds, and rigorous prospect ranking, ensuring that 10-15 of the most promising targets are drilled each year. We have successfully executed this approach for several years, establishing efficient, commercially driven processes to evaluate opportunities. Over time, this has led us to prioritize near-field exploration, with 80% of our wells drilled close to producing fields and existing infrastructure and 20% targeting less mature areas. Efficient and advanced drilling, one of Aker BP's core strengths, will remain critical to exploration success in the years ahead. To maximize value creation, we have positioned ourselves as operator for nearly 70% of our licenses. A strength that is underscored in the latest licensing round, where Aker BP was awarded more operatorships than any of the other companies on the NCS. New technology is also in this area set to become a game changer. The rapid rise in generative AI is unlocking new possibilities in analyzing vast and complex data sets. One of my personal favorite examples is our exploration robot, a powerful AI tool that processes immense amounts of subsurface data, identifies patterns, and pinpoints potential prospects with unprecedented speed and accuracy. I am convinced that our ability to leverage AI will provide Aker BP with significant competitive advantage in the years ahead. Moreover, innovations like Ocean Bottom Nodes, or OBN for short, are transforming seismic imaging. By leveraging 4D seismic imaging from seabed-based networks, we achieve drastically improved imaging quality, leading to better prospect evaluation and decision-making, and in the fourth quarter, we entered into an OBN alliance with PXGEO. This partnership aims to enhance the commercial viability of OBN by driving down cost, making it an even more powerful tool in our exploration efforts. Our 2025 exploration program marks a new record for Aker BP in both scale and potential. While this creates a lot of near-term excitement, it's also a decisive step towards our overarching goal, leveraging our strong position and expertise to maximize the value of the remaining resources on the NCS. In addition to a series of ILX wells, we're also investing in wells with the potential to unlock new areas and drive future infrastructure development. One key well in our program is Rondeslottet, which we will revisit this spring, following our first attempt in 2023. If we can successfully unlock this tight reservoir, the upside potential is significant. Another exciting prospect is Bounty, which we're currently drilling. It features a unique geological structure, and if our trap theory proves correct, it will contain a substantial oil accumulation. So keep your fingers crossed. I know I am certainly. Mergers and acquisitions have also played an integral part in our strategy and become a key driver of Aker BP's strong growth story over the past decade. Now, winning in M&A is not about having the highest bidder. In Aker BP, our team spends most of its time studying and analyzing assets and companies to figure out what would be a good fit and what is the right valuation. And not least, how we can integrate the target and take out synergies. Our overarching objective is clear: increase shareholder value, either by increasing dividend capacity or reducing risk. And to be very concrete, these are the first questions we ask. Is this deal accretive to our cash flow per share? Do we have a robust financing plan? How is the impact on our risk profile? Next, we assess the potential upsides. Can we unlock additional value from the resource base? Can we operate this asset more efficiently? Would aligning interests lead to better decisions and more ultimate recovery? And what synergies can we realize? If the answers are compelling, we move forward. And with our distinct capabilities in digitalization, alliances, and industry-leading performance, and not the least our proven track record in integration and synergies, I am convinced that Aker BP can continue to create superior value for M&A. And just to be clear, our home is the NCS, and we have no plans to expand elsewhere. Thank you, Karl. We are now two years into our six-year value creation plan launched in the beginning of 2023. A plan that not only delivers value-accretive growth into the 2030s, but also high cash flows and significant distributions to shareholders along the way. We are progressing well, leaving behind us two very strong years, both in terms of operational and financial performance. We start 2025 with a fortified financial position and an opportunity to create even more value. And with that backdrop, our capital allocation priorities remain firm: maintain financial flexibility, invest in highly profitable growth, and distribute the value created back to our shareholders. Let me start by providing some details on the recent developments in our financial position. Building financial capacity and securing access to capital is a continuous process. Over the past year, we have successfully executed several transactions in the bond market. By issuing new long-term debt and repurchasing short-term maturities, we have increased our financial flexibility by moving most of our maturities beyond the startup of our ongoing field development projects. Issuing our first 30-year bond is a milestone. To me, it illustrates that the US bond market, with its high-quality institutional investors, shares our confidence in the long-term demand for oil and gas, the attractiveness of the Norwegian Continental Shelf, and Aker BP's long-term strategy and value creation potential. So where does this then leave us in terms of key balance sheet metrics? Net debt remains low at $3.3 billion, slightly below the level at the end of the second quarter last year, and our leverage ratio remains conservative at 0.3 times net debt to EBITDAX. Our financial capacity has strengthened, not only by increasing available cash from 2.8 from end 2022 to $4.1 billion at the end of 2024, but also by reducing our shorter-term commitments and liabilities. First, as we progress our ongoing investment program, our point-forward committed CAPEX is naturally reduced. We're also starting the year with a lower tax overhang than in both 2023 and 2024. In fact, our tax payables have been reduced by over $2 billion since the start of 2023. And finally, with the mentioned refinancings, we have now less than $300 million in debt maturing before 2028, down from around $2 billion only two years ago. In sum, Aker BP's balance sheet has never been more robust, and we are well positioned to continue delivering on our value creation plan. As already covered today, we are progressing well on our project portfolio. Four of the tieback projects in the Alvheim and Grieg Aasen areas have already been delivered. The remaining ongoing project portfolio consists of very robust, high-return projects with an average full cycle break-even oil price between $35-$40 per barrel. This means an unlevered IRR of around 25% at an oil price of $65, and at that oil price level, we expect the projects to be fully repaid within one to two years after first oil. As we progress closer to production start, we not only de-risk the plan, we also leave behind investments. And for reference, the point-forward break-even oil price for the ongoing project portfolio is now $25-$30, and with an IRR above 40% at a $65 oil price. When it comes to the investments needed to deliver our projects, the total CAPEX is in line with our estimates when we sanctioned them back in 2022 and what we have presented to the market before. There are some minor pluses and minuses within the portfolio and some adjustments to phasing, but the total investment level remains largely unchanged. One concrete example worth noting is that in this updated outlook, we have now included the investments related to developing the East Frigg discovery as part of the Yggdrasil development. This also means that the CAPEX outlook here matches the production profile presented earlier for what is called base production and ongoing named projects, taking us to around 525,000 barrels per day in 2028. As for new investments beyond this plan, we expect them in the range of $15-$25 per barrel, where investments near existing infrastructure is typically in the lower end. And as always, I would like to highlight the importance of understanding the Norwegian tax system, which reduces the overall financial exposure of investments. In the past two years, we have invested around $8.1 billion on a pre-tax basis, while the after-tax exposure is below $1.5 billion. Our value creation plan from 2023 to 2028 is summarized on this slide. The plan remains firm as we enter the third year, having built more resilience and opportunity for upside. If we start with the graph to the left, this is the estimated accumulated cash flow from operations at various oil prices after netting out the tax deductions for our CAPEX. We here also show the actual cash generated in 2023 and 2024. The price scenarios on top are point forward from 2025 to 2028. On the other bar, we show the estimated uses of this cash. One interesting observation is that the cash flow from operations in 2023 and 2024 alone covered the estimated full investment program from 2023 to 2028 after tax. More interesting is, of course, to look at the years ahead. This illustration underscores the substantial value created available for distributions in most plausible oil price scenarios over the next four years. This point becomes even clearer when looking at how cumulative free cash flow develops over the next four years in the graph in the middle. 2025 is expected to be a year with relatively low free cash flow. However, using the same assumptions, we will see increasing free cash flow already in 2026. By 2028, we estimate to have generated between $9-$14 billion in free cash flow at oil prices between $65-$90 per barrel over the full plan period. For reference, this is between 65%-100% of the current market cap of Aker BP. Going forward, this equates to between approximately $5-$10 billion from 2025 to 2028, or 35%-70% of the current market cap. An important question is then how our balance sheet will develop over this period. And we have already talked a lot about how we have optimized our financial position to prepare for this period. And the graph on the right then illustrates how our leverage ratio is expected to develop over the next four years at various oil prices, assuming a dividend that continues to increase with 5% per year. We estimate to maintain a leverage well below 1.5 times, which is our internally set threshold not to exceed for extended periods at most plausible oil price scenarios over the period. And even in a flat $50 oil price scenario for the next four years, we will only for a short period exceed 1.5 times before deleveraging back down. To me, this really demonstrates the attractiveness and resilience of our value creation plan, and not the least, the resilience of our dividends through the period. When it comes to dividends, the key principle for Aker BP continues to be that shareholder distributions shall be resilient, but also reflect the financial capacity through the cycle, considering both our financial outlook and the credit profile. As we enter 2025 with a strong financial position and high underlying cash generation from our producing assets, we have a robust foundation for staying true to our ambition of growing the dividend by at least 5% per year through this investment period to 2028. The board of directors has therefore proposed a total dividend of $2.52 per share for 2025, paid quarterly. Now, to round off, I will walk through our other key guidance parameters for the year. Overall, our guidance for 2025 remains in line with our previously communicated long-term plans. We expect average production per day between 390,000-420,000 barrels per day. Our production estimates are based on P50 bottom-up assessments across our portfolio, and the range reflects the simulated uncertainty of those estimates. The year-over-year reduction is driven by natural decline across several of our fields, which we also expect somewhat to continue throughout 2025. In terms of in-year phasing, we expect higher production in the first quarter and then lower in the second and the third due to seasonal maintenance. Operating expenses are expected around $7 per barrel, and variations between the quarters follow the seasonal maintenance and phasing of well-maintenance activities. Total CapEx remains in line with the communicated investment program we initiated back in 2022, and for 2025, we expect CapEx between $5.5 and $6 billion. This range reflects that we have pushed the approximately $200 million of underspend in 2024 into 2025 and added sunk cost related to the East Frigg discovery as the project has now passed concept selection and will be developed as part of the Yggdrasil area. Lastly, the range in itself also reflects some of the inherent uncertainty related to phasing of spend on the projects. Abandonment expenditure is expected to trend down to $150 million in 2025, with P&A scope on Valhall and Ula being the main drivers for the spend. Lastly, 2025 is expected to be a very exciting exploration year. We are currently drilling four wells and plan for another 11 wells during the year, with a total spend including seismic of around $450 million. With that, I conclude my part of the presentation. As always, I will now hand it back to Karl for some final remarks before we move on to the Q&A session. Thank you, David. Before we begin the Q&A session, I'd like to quickly summarize. One, Aker BP delivered an outstanding performance in the fourth quarter and throughout 2024, achieving low production costs, low emission, and production at the high end of our guided range. Two, our ongoing projects are progressing well, and execution is on track with total CAPEX estimates unchanged. Three, we have a clear and well-defined plan to sustain production above 500,000 barrels per day from 2028, with even greater ambitions beyond that, amongst others assisted by an increase in volume estimates for Yggdrasil and Johan Sverdrup. Four, we remain committed to delivering value, including a 5% increase in dividends for 2025. We will now, as usual, take a short pause before opening the Q&A session, and to participate, please use the Teams link provided on the web page. If you prefer to listen only, please stay tuned, and we will resume in one minute. Welcome back, and we are then ready to start our Q&A session, and as usual, Kjetil will guide us through the Q&A session. I'll hand over to you, Kjetil. Thank you, Karl. Today's first question comes from Matthew Smith of Bank of America. Please go ahead, Matt. You're muted, Matt. There you go. Start again. You were muted for a couple of minutes. Perfect. Good morning, guys. Thanks for taking my questions. Thanks for a great presentation, as ever. A couple of questions from me. I'm sure some first on Sverdrup. I'm sure someone else will perhaps ask about, you know, potential to beat expectations there this year. So actually, I wanted to focus my question. I noticed in the press release, you noted that yourselves and Total have called for a redetermination process on the equity stakes there. So I wondered if you could perhaps touch upon sort of what's changed since 2015, what you might expect from the outcome, and the timelines there might be useful to understand as well if we could. And then on my second question, if I shift away from Johan Sverdrup, I wanted to touch on Wisting, if I could. I suppose a few years back, you know, ultimately that project, I don't think quite it was never canceled, but put on pause. I don't think it quite made it through your sort of investment hurdles at the time. So just interested to understand how the project concepts evolved into, you know, what's presumably looking like a better project today. Excellent. Thank you, Matt. So let me start on Johan Sverdrup. And first on the performance of the field itself. I think it was pretty clear in the presentation that Johan Sverdrup has been consistently overperforming, and I would say even outperforming expectations. That's also the case for 2024. And now with production estimates in 2025 being fairly close, or quite close to the 2024 numbers, I think this history is repeating itself. And remember, Johan Sverdrup is still a very young field. I mean, out of an estimation of roughly 3 billion barrels, we only produced a barrel, a billion barrels. And also the recovery estimates have now been increased by the operator, an increase we actually truly support from 68%-75%, which is about 100 million barrels net to Aker BP. So I think you should expect more from Johan Sverdrup. And I'm actually really, really positive also to the way the field is being operated by Equinor. Now, on the second question, which was related to the call for redetermination. So in the original unit agreement, there was one possible call for redetermination, which was the first week of January. And as you've seen, both us and Total chose to exercise that option. Now, remember, Total and us are essentially weighted towards the license 501, whereas the operator, Equinor, is balanced across 501 and 265 and the remaining small licenses. Yeah, the process, I'm guessing, will take, let's say, 12-18 months or so. I'm not going to speculate on the outcome, but obviously, it is quite clear that we wouldn't have called this if we didn't expect a positive outcome. Now, a final comment maybe is that this redetermination is only about the STOIIP distribution between the different licenses. It is not about value distribution or other, and if we are successful, payment will actually be in kind and not in dollars. We'll, of course, come back to this as the process progresses. Now, on Wisting, and you're absolutely right, it was paused in 2022 for many reasons. One was increasing cost, and second was a large, big, I would say, congestion of the vendor pipelines. Since then, we've been optimizing the field. We've been drilling geo-pilots to verify caprock capabilities, and we've been optimizing the subsurface and subsea layout. That work is still ongoing. My expectation is that sometime this year, we will make a concept select and then move forward with the project. Also, here, I'm actually quite positive to how the operator has been optimizing the project, and now it's mostly about execution strategy. You were still muted, Matt. I saw you said something, but okay. let's take the next question. We move to the next caller, who is James Carmichael from Berenberg. Please go ahead, James. Hi, morning, guys. Hopefully, you can hear me. We've, I guess, you know, we sort of hear a lot of value over volume in the industry, but I guess you have sort of outlined a volume-based ambition today to maintain production over 500,000 barrels a day into the 2030s. I think in terms of ILX and IOR, you have demonstrated a good track record, but how confident are you that there's sort of accretive M&A opportunities existing to sort of help you sustain that level of output and, you know, achieve the returns you're looking for? And then, I guess, just secondly, David's sort of section at the end, all the charts stopped at 2028 when Yggdrasil comes online. If you extended those out further, you know, based on the current portfolio, what do you think is the sort of dividend capacity in the business, given how sort of cash tax situation develops? And I guess at some point, you do need to start paying back that debt as well. Thanks. Okay, thanks, James. Excellent questions. So first of all, the production profile, and let me be really, really clear. Aker BP has always been about value and will consistently be about value. So this is no change. We're not going after volume just for the sake of volume. We are going after volume because we believe that these projects are profitable, that they create shareholder value, and they're basically in line with our existing strategy to maximize the recovery factors given certain thresholds, which I'm sure, James, that you remember. And then remember this base profile that peaks at 2025, the dark blue one in the charts. That consists of all the producing fields. That is all 2P reserves. It consists of all the mature field developments, including now East Frigg and Johan Sverdrup Phase 3 as an example. Then the light blue wedge that is necessary to keep production stable is basically new IOR measures in the existing fields. As you've seen, we've consistently demonstrated over the last decade that we're able to do these kinds of projects. I can assure you, we are relatively confident standing here today that we will be able to deliver this within the organic profile without, let's call it, big discoveries or M&A opportunities. If we did make big discoveries, which I'm really hoping we'll do, I have a really, really exciting exploration program for 2025, or there is an M&A opportunity that will, of course, be in addition to the +500,000 barrels that we have talked about today. Then, David, I'll hand over to you on the question of capex cut-off in 2028. Yeah, so I think the way that we think about this is that we initiated the plan beginning of 2023, six years up until the end of 2028. That's what we are now reporting on in terms of the value creation potential, but also, of course, in terms of how we are progressing against that plan. What we're also indicating now for the first time is how we see cumulative free cash flow, you know, accumulate over time and the value creation potential from that, not only the sort of normal sources and uses that we have shown in the past. Lastly, we also show how the balance sheet is sustained over that period. So we do see that we will be increasing leverage slightly over the next couple of years, obviously depending on oil price, but then we expect to delever significantly towards the end of the period. And I think that also indicates the balance sheet robustness and the cash flow generation that's available both for repaying debt, if that is something that we choose to do, but also distribute more value back to shareholders. And then I think when it comes to indicating what the production profile looks out into the 2030s, I think this is the first time that we do this. We have been focusing a lot over the past few quarters reporting to the market on how we are progressing, you know, the ongoing projects. But now we are illustrating that there is a large hopper of early phase projects and infill opportunities that will sustain production further out. And of course, with a 500,000 barrel per day production, with a production cost around $7 per barrel, there is obviously significant free cash flow that will be generated that will enable us to sustain also distributions. Thanks, James. Let's take the next question, Kjetil. Yes. Of course. The next is from John Olaisen from ABG. Please go ahead, John. Yeah, thank you. And thanks for taking my question. Your CapEx guidance on slide 74 is a little bit more details on a question from James, actually. It includes CapEx for only ongoing PDOs. But what will CapEx look like towards the end of this decade if you're going to achieve 500,000 barrels or more around 2030 and the years beyond? Y eah, you want to start? I can do that. It's your favorite topic. Exactly. No, so the way that we think about this, right, is that the CapEx profile that we're showing on page 74, that correlates perfectly well with the dark blue production profile that we're also indicating. So there's a one-to-one match there. And then the way that we think about it is that if we are to add new additional projects on top of this, we see a range of CapEx between, you know, somewhere between $15-$25 per barrel, where typically, you know, tie-ins, etc., infill wells and so on will be in the lower end of the range. And then depending, of course, on the type of development of larger fields, we'll be somewhere in the middle or higher end of the range. So the way that we see it now is that we are in a sort of peak CapEx period, and then CapEx will decline over the next few years. And then depending, of course, on what type of investments we choose to sanction from 2028 and onwards, that will then, of course, define what the CapEx profile will look like. But I'm sure that you guys know that we will be producing at 500,000 barrels per day. That's 160-something million barrels per day. And then if you're saying that CapEx per barrel is between $15 and $25, I'm pretty sure that you will be able to figure out what the sort of a sustaining CapEx profile might look like. And maybe just to follow up a little bit, John, when we talk about $15 to $25, this is not the number we picked out. This is basically a reflection over the fact that we've been carrying out this kind of activity on Valhall, Alvheim, Skarv, Edvard Grieg now for almost a decade, and therefore have a pretty solid and robust database of what these kinds of projects are actually costing in terms of dollars per barrel. So it's not just a number we picked out. Then just to add to Karl's comment on that is that, of course, now we have included the East Frigg discovery into the Yggdrasil area. And when you look at sort of what the, call it, incremental CapEx on that versus the resources that we've been able to add to the development, you can see that those types of area developments where you have a lot of infrastructure in place, you're really able to add on at a low cost per barrel. Yeah, for sure. Finally, the follow-up on this. For those new non-sanctioned projects, do you expect to have the same full cycle break-even oil price levels of $35-$40 for those as well? Or I guess at some point on the NCS, the full cycle break-even oil price will have to come up. Is that something you're seeing within the current framework or time horizon as well? The first part of your question, John, yes, we have not changed our investment requirements for this project. And that means that we actually see this at roughly the same level. And that almost comes by itself. If you look at the kind of project, if you do $20, you're roughly at around $30 break-even. And then there's a relatively small amount of incremental OpEx. So it's quite natural and almost mathematically follows from the assessments of CapEx per barrel. And then, of course, when you enter into a little bit of a longer horizon and you look at the Norwegian Continental Shelf, right, there are basically three big pools of remaining resources. The total remaining resources in a little bit of an optimistic state is roughly 40 billion barrels on the Norwegian Continental Shelf. Three basic big pools. The first one is small accumulations. The second one is HPHT. And the third one is tighter reserves. So we're actually targeting all of these three pools, reducing cost, optimizing production, etc., etc., just to make sure that we can still invest with the same level of profitability and not end up in this incremental increase that you illustrated, John. But if we were to do nothing, you would be perfectly right. However, we're not standing by and idly just watching this happen. Right. I'll let some other analysts have some questions as well. So thank you very much for taking the question. Thank you, John. Yes. Then the next question comes from Vidar Skogseth Lyngvær from Danske. Hi. Thank you for taking my question. Congrats on the quarter. First, CapEx drivers in 2025. You now shared a new CapEx guidance between $5.5 and $6 billion. Could you just touch upon the main CapEx drivers for 2025 through the year, like if it comes in the high end or low end? Is it progress on your activities or is it cost inflation? That's the main drivers for CapEx in 2025. Thank you. Yeah. So if you were to think about 2025, I think we moved roughly $200 million from 2024 into 2025. And then I would say if we end up in the high end of the range, that is because we have had a very high productivity. That means we've taken deliveries of lots of this stuff. So it's mostly procurement. Cost is not really an issue. Yeah, well, it is an issue, but it's not really an issue in the estimates because the contracts have already been set and the prices have been fixed. So this is basically about how much is delivered inside of 2025 and how much is then delivered crossing over to 2026. And I'm sure David will correct me there, but actually I am hoping that we'll end up in the higher end of the range because that will demonstrate that we have been very successful in delivering the program for 2025. So it's basically a timing issue when we take deliveries. And then by the end of 2025, we have taken deliveries of most of the external packages and parties and procurement. And then for 2026 and 2027, it's basically hours and assembly activities. I won't correct you on that, Karl. That's good. That's the first. Thank you. That's exactly where I was leading to, that the higher CapEx means faster progress. And that's generally typically good for NPV. You mentioned to build upon John's question, $15-$25 per barrel. Are we talking real $20-$25 or nominal dollars then? And do you think within, if sanction would be within that range as well? I'll leave that to you, David. I think you can think about this as nominal. And yes, it's the answer to this thing. Brilliant. Thank you. That's what I had for you guys. I'll recap. Thank you. Yes. The next caller is Sasi Chilukuru from Morgan Stanley. Hi. Thanks for taking my questions. I had two, please. The first one was from a strategic point of view. The current portfolio is more geared towards oil, even when you look in terms of reserves or production. I was just wondering if there was any preference to make the skew more balanced if you're looking to add more gas reserves, either organically or inorganically. The second was on M&A. You clearly, you laid a very clear criteria for acquisitions. I was just wondering if you're likely to see any disposals of maybe any non-core assets, if there are any, or even reducing the stake in assets where you have a concentrated position. Yeah. Thank you, Sasi. Yeah, this discussion around oil and gas, I find that a little bit complicated, to be honest. I don't necessarily subscribe to the viewpoint that some are presenting that there will be an extremely bullish gas market, particularly in Europe for the next few years. I actually think that there's likely to be much more volatility than we currently forecast. So yeah, my view on this is that in terms of exploration, we are looking for hydrocarbons, so I've told my exploration team, don't care about gas, just go for hydrocarbons. The bigger, the better, and then we'll deal with it as it occurs. From an M&A perspective, I have no real preference, but I am more cautious on the gas side in terms of cost, so we want the answer to this. We won't target it, go after an increase in gas in the next few quarters from an M&A perspective. But of course, if we do make a big discovery in gas, which I really do hope we do, we'll develop it to the best of our abilities. And then maybe just add on that, Karl, just for reference for everybody's understanding. We do, with the organic development portfolio that we have, we will have a slight increase in the ratio of gas to oil once that was about to make. Oh, sorry. Okay. No, go ahead. When Yggdrasil comes on stream with the Munin field and of course also Fenris in the Valhall area. Sorry for stealing that, Karl. No, no, that's fine. Absolutely. We didn't practice. No, no. And then when it comes to the M&A, we really like the position. We don't really feel a need to dispose of assets. Most of these assets, we are acquired for a reason. We are also pretty predisposed to liking high equity assets where we can actually take benefit of our own performance rather than having licensed partners take the majority of the benefit from high performance. So I'd much rather try to stay in the driving seat and then be the master of my own fate than ending up in a situation where that's the opposite. So I don't think you should expect major disposals, no. Very clear. Thank you very much. Thank you, Sasi. Then the next caller is Teodor Sveen-Nilsen from SpareBank 1. You have to unmute, Teodor. Sorry, Teodor, we can't hear you. I think you're muted. Still muted, unfortunately. Sorry, can't hear you still. We have a technical issue. Just please hold for a couple of seconds. We'll check it out. Let's just move to the next one and we'll put Kira back in the queue. Yeah. We'll come back to you later if you disconnect and reconnect, and then we'll try again. We'll move on to the next caller in the meantime, Victoria McCulloch from RBC. Hi, morning all. Hopefully you can hear me okay. Thank you, Victoria. Thanks. I'll ask the predictable question. If we assume Sverdrup is flat year on year, production potentially guidance looks a little bit light. Maybe a part B to that, you mentioned that the Edvard Grieg decline has tapered. What are you expecting decline-wise in Edvard Grieg? And have you been cautious on your production guidance as a result? And if there's still room for a second question, is there any color you can provide in what the 2P reserves replacement ratio was in 2024? Thanks. Yeah. Do you want to comment on guidance, David? Yeah, I can definitely do that. So I mean, as we also said in the presentation, right, so the guidance is sort of reflecting a bottom-up P50 estimate. And there is always uncertainty around the midpoint, I mean, in terms of both production efficiency, planned downtime, etc. So the way that we think about this is that we expect now Sverdrup to produce close to the levels that we saw in 2024. And then at the rest of the portfolio, as I mentioned when I was presenting, is that we do have an underlying decline in the operated portfolio through the year. On Edvard Grieg, the decline rate has tapered off. However, if you take the average of the production in 2024 versus 2025, we would still see a lower production output of that field. And then similarly, we do also have some decline on Valhall and Skarv throughout the year. That's the basis for the slight decline in the production in 2025 compared to 2024. And then when it comes to RRR, we have not published the reserve report yet. So that will be done in, I guess, in March. Yeah, we'll have to come back to that. But one additional point maybe on the guidance. The last few years, we've had a lot of new wells and new field developments coming on stream and included in the guidance. And the production level in the guidance has been pretty good, right? But as you point out, maybe a little bit conservative for 2024. In 2025, I actually do believe that we have still a P50 estimate. And of course, we'll do what we can to maximize production. But I wouldn't foresee this as a, it is basically a bottom-up P50 estimate. And that's how you should look at it. It's not something that we have tuned. Thanks very much. All right. Then the next caller is Chris Wheaton from Stifel. Good morning, guys. Thank you very much indeed for another excellent quarter. Two questions, if I may. Firstly, can I come back to the point John was making about medium-term CapEx? It feels like, like everyone, I've got production, I've got CapEx estimates falling off 2028 onwards. It feels like if you're treating this as a manufacturing business, which absolutely is the key to your success and how you've made this amazing business over the last 10 years, CapEx isn't going to fall off. And we should be expecting that sort of $3-$4 billion of spend post-2028 to be maintained. Because if you've got a supply chain that's set up to deliver that, I would have thought that is what the pace you want your supply chain to work at. I'm interested then in understanding what the risks are to that unit CapEx number. Because as Karl Johnny, you described three areas being small accumulations, HPHT, and tight reservoirs. None of those scream to me average costs in line with the average you've been delivering on Norway so far. But also, I'm interested in, do you have to deliver exploration success to actually hit that total? Because are you going to maintain that 500,000 a day? Because if the balance isn't going to work, then you're kind of reliant on a lot of infill explorations and success kind of delivering those volumes. That's kind of my first question. Now I've got a question on dividend for David. Yeah, excellent. Well, I actually buy into your knowledge on manufacturing. But in reality, when you look across a lifetime of a field, it doesn't quite work like this, right? It's a good example, maybe just to illustrate the point: Yggdrasil, where we've invested now in the infrastructure. And then East Frigg comes on stream. It's roughly 40-50 million barrels, but the incremental CapEx is only 500. So there you got a 10 million. The next one will be even lower because you basically have invested in infrastructure, which is sunk cost. And then the incremental cost as you're adding new volumes to the infrastructure base is significantly lower. Now, if you were to look at the end of the field lifetime and just average everything out, your logic will actually work perfectly. When you're in the middle of this field development, we're taking the benefit of the fact that we're investing a lot in new infrastructure, which means that as we move into 2027, 2028, and 2029, and 2030, and 2031, etc., the extra CapEx needed to bring new barrels to the market is significantly lower than the average CapEx of the existing field development, right? That's why we are pretty confident that the way we've set up the business now has resulted in a vehicle that will deliver flat productions well into 2030 with a relatively low CapEx estimate. It's basically taking the benefit of the huge investment program we're in the middle of right now. On your question of are you dependent on exploration success? For the 500,000 barrels into 2030, not really. If you were to apply a ruler to that, you would probably end up somewhere in the range of 50-60,000 barrels, right? And if you were to add the existing program to this, you would quite quickly, Chris, come to the conclusion that, yeah, maybe an ILX target or two, but that's about it. When it comes to the additional ramping up significantly, the even lighter blue on that page, then you are dependent on either exploration success or an M&A activity. So that's the reason for your assessment around it. And of course, when it comes to the value chain, we're already discussing how to change tieback solutions, how to apply modern and new technologies to tight oil reservoirs. And we're learning high pressure, high temperature as we speak, drilling the Fenris field and developing the Fenris field. So for us, this is a very strategic positioning where we're basically doing two things at the same point in time. We're executing on the existing project portfolio, and then we're developing technology and practices for the next generation of projects. That's really interesting. Brilliant. Thank you. That sort of helps put some framework around my thinking. Thank you. And David, a question into you on the next thing on the run to 2030, which is the sustainable level of dividend. And we've talked about the sustainable level of CAPEX, therefore being the order of $4 billion plus or minus, including exploration and decom. Therefore, on my sort of back-of-the-envelope calculations, it feels like $2 billion a year is the kind of the right dividend number that you could sustain, depending on what kind of balance sheet you want to run. And I guess that's the question. Does two billion feel the right number? And what kind of balance sheet do you need to make sure you can pay that and deliver that steady state 500,000 a day goal that we're sort of starting to talk about today? Yeah. Well, I mean, our key message today is that the value creation plan that we have put in place generates a lot of value and a lot of free cash flow to shareholders. And all the value that we create will be distributed back. I won't give you sort of a number here today about what type of sort of a steady state dividend will be 2030 and onwards. But we have a very clear policy that we would like the dividend to grow by a minimum of 5% throughout the investment period that we're in now. And then we know that there is a lot of upside to that, obviously depending on oil price, etc. So I think that's as far as I will go in terms of providing more details on the longer term. Okay, that's great. Thanks very much indeed. Thank you, Chris. Let's move on, gentlemen. Yes. I have had a chat with Teodor on the side, so I got his questions on email. So I'm reading them now. On Wisting, shallow reservoir, is there any challenges versus North Sea developments? And then the second question was on Yggdrasil, what will drive the resource increase from 650 to one billion barrels? Sorry. Yeah. So thank you, Teodor. And we do apologize for the technical difficulties. We'll try to fix it next time. On Wisting, yes, it's a shallow reservoir. The two main complications on this is how competent the overburden is, which is one of the things that we verified with the geo-pilots last year, which demonstrated that the assumption we had back in, yeah, the start of 2022 was correct. And we have therefore adjusted up the reserve assessment again back to where it was. The second one is that because you only have 300 meters of burial depth, you need a much more distributed SPS system or SURF system because you can't really have long wells that go out kilometers in horizontals as they're traveling out from the field center. So there will be a bigger than usual footprint on the SPS. That are two basic differences on Wisting compared to an ordinary Norwegian Continental Shelf subsea development. On Yggdrasil, yeah, okay, let me just run you through the story. We PDOed Yggdrasil at 650 million barrels. Even at that point in time, and I think it was highlighted in the submittal to the Parliament as well, there was about $800 million in upside in totality if you were to look at the IOR possibilities. When we submitted the PDO, we were very clear that we saw a lot of upside in the field. That is IOR wells, its new field development, its prospectivity in the area. So much, in fact, that we only dedicated about half the well slots to the existing PDO well program and half to the future tie-in wells. Then we have drilled now East Frigg and getting a firmer understanding of what's happening between Frigg Gamma Delta reservoir and the old Frigg gas reservoir. We've added East Frigg now, made a concept select on that. That's about 50 million barrels, about $500 million in CAPEX. We're seeing a lot more of these kind of discoveries. I think a previous quarter, I said that this had a potential of being several hundred million barrels. That's the key reason in the East Frigg area. Then we've drilled geo-pilots into Frigg Gamma Delta, which is proving very positive. In totality, it's about an increased understanding of the reservoir outside the existing fields. Then it's a better than assumed assessment of the existing fields and the capabilities we have in the ongoing field development that adds up to this 1 billion barrel resource ambition that we are putting in place today. I must say, Teodor, I'm actually really, really proud of the team that's been working this. Most of this we acquired for a few cents on the dollar and turned it into a huge business opportunity. On behalf of Teodor, thank you for a brilliant answer. And now. It's a lot easier when you do it, Kjetil. Now it's Yoann Charenton from Bernstein. Welcome, Yoann. Thank you for waiting. Good morning, everyone. We'd like to ask three questions. One on M&A, if you don't mind, because you have outlined the potential there. When you look at the whole NCS, do you still see some undeveloped discoveries sitting in the wrong portfolios? And if so, can you help us put a figure on this in terms of barrels? That would be the first question. Second question, it's on distribution. Is it possible to remind us why your near-term distribution envelope does not include buybacks? And third question will be related to CapEx. You have delayed the drilling of two producers at Sverdrup to 2025. How much CapEx savings did this generate in the fourth quarter? And how much CapEx will East Frigg and Sverdrup Phase 3 add to slide 74? Yeah, okay. Excellent, but quite detailed questions, Yoann. Let me try to answer them as precisely as I can. On the M&A side, when you look at the opportunity set on the Norwegian Continental Shelf, I think there are a lot, there are quite a few drivers for what I believe will be a consolidation on the NCS. It used to be the fact that there was a lot of undeveloped reservoirs sitting in the wrong hands. That is actually still the case. But now it's more about productivity and performance. So it's more about the fact that we can see more value than existing owners, right? So it's not that it's unclear that there is a value there. It's actually, I would say, there's relatively clear that there is a value there. It's quite clear to a lot of the actors on the Norwegian Continental Shelf. As I tried to outline a bit earlier today, I do believe that we have a world-class execution engine with extremely high reliability and extremely high performance. That means that as we are adding these or potentially adding these companies and reservoirs to our portfolio, we're seeing more underlying value than what was on the page when we bought it. That is the key driver. This is why I'm so preoccupied with operational excellence. It is because it is all about, it's not about negotiating to a better deal. It's about outperforming as soon as we can. You asked about, should we do CapEx first? I can, yeah, do CapEx, yeah. In terms of Sverdrup CapEx, this is immaterial. The two wells that were pushed into 2025, that's driven by, call it the time it has took to put the other wells on stream. That's not the material part of the, call it the $200 million that we have said that were moved from or phased from 2024 into 2025. When it comes to CapEx on East Frigg and Johan Sverdrup Phase 3, that's all included in slide 74, so the CapEx outlook, because that's also then included as part of the production in the dark blue area. I'm glad that you asked that clarifying question, Yoann. And then on buybacks? Buybacks, go ahead. Yeah. To remind you, as you said, our dividend policy does not exclude buybacks, but we have said that the main vehicle for distributing value back to shareholder is a reserves-based dividend that grows in line with value creation. And then buybacks is a part of the toolkit, but we have not used it yet. That's very clear. Thank you. Thank you, Yoann. Let's move on, Kjetil. Yes. Then next caller is Matthew Cooper from Barclays. Hey, Matt. Hi, guys. Good morning. Hopefully you can hear me okay. Yeah, we can. Absolutely. Go ahead, Matt. Perfect. Okay, so three questions from me, if you don't mind. So firstly, just a quick follow-up to the earlier questions. So in order to hit the kind of base case production profile, is it fair to assume 2029 and 2030 CapEx will be similar to CapEx in 2028? Second question, I wondered if you could talk about 2024 exploration in terms of success rate. And when do you think the quality of opportunities might lead you to decrease exploration activity? And then third question, do you think you've now reached the kind of technically possible limit to go around Sverdrup with current CapEx? And also separate to that, if you could just talk about how much in place upside there might be around Sverdrup. Thank you. Yeah, okay. On CapEx 2029 and 2020, I think we answered this before. I think you should assume that the CapEx profile that are depicted on page 74 is correlated to the dark blue production profile. And then after that, assume $15-$25 per barrel of additional cost. But just to clarify that, so the CapEx that we then do up until 2028 should be able to sustain also the dark blue area in 29 and 30. So that's to just be absolutely clear on that. And then if you were to do those numbers, I don't think you're too far off. On exploration success rate, I think we delivered 15 wells last year, did nine discoveries, two out of those were appraisals. That leaves us with seven wells, and two of those were probably in the range of technicals, which leaves us roughly a 50% success rate in 2024. So it's not really about success rate. It is about finding the right prospects at the right timing to add into the field developments. And then in 2025, I wouldn't be surprised if we ended up with roughly the same success rate. And then finally, your question was technical limit on 75%. I'll never say never because this field is going to live for another 30 years, right? So I wouldn't say that this has now reached the technical limit, but it is pushing it. 75% is quite high. The tool hasn't really fundamentally changed. Typically, this happens a bit later in the field lifetime when you get to a better understanding of the totality and the volume distribution. There might be some upside to the STOIIP numbers yet. Well said. Thank you very much. Yes. Next caller is Kate O'Sullivan from Citi. Hi. Thanks for taking my question. I appreciate the production outlook you've presented today into the 2030s. The chart you've shared on slide seven there shows potential for the M&A and exploration levers to bring your production above 600,000 barrels a day by 2030. My question is just really around ambition. Interested to hear how keen you are to move above the 525 by the end of the decade. That would depend on the quality of the opportunity, Kate. So as we've been really clear a bit earlier today, and I don't want to be misinterpreted on this, we are all about value. So we're never going to invest in field developments, M&A that don't really create fundamental shareholder value compared to the thresholds we've already set in place and communicated quite clearly to the market. That being said, there's quite a lot of high potential prospects in the existing drilling portfolio in our Aker BP, which could sustain this, Bounty being one, Rondeslottet being the others, and there are quite a few others. And then there is a lot of M&A opportunities. So this is why we've chosen to illustrate that even post 2028, there might be a bigger upside than we previously communicated in the production profile in our Aker BP. Great. Thanks. All right. Next question is from Mark Wilson of Jefferies, the one and only. Okay. Thank you. And apologies for having more questions. But I'd just like to come back to Wisting. And obviously, this speaks to the post 2028 view. I would say from a strategic point of view, it sounds like Wisting would be kind of outside the envelope or framework you talk about, the $15-$25 billion CapEx, that huge subsea spread, and the location of it up in the Barents. I do notice there's no exploration wells in the Barents in the plan for this year. So my question would be that, how would you point to Wisting fitting within the parameters of all the other assets that you've brought through so successfully? And then the second one for David, you're very clear to say that a buyback is part of the toolkit. Would it be fair to say to continue a 5% increase of a dividend return each year, you actually need to include a buyback to reduce that share count longer term? Those are the two. Thank you. Yeah. So on Wisting, and again, I don't want to forerun the concept selection decision, but we haven't really changed our investment criteria. And currently, it is still the ambition that Wisting will be sanctioned inside the existing investment criteria. So let me be quite clear on that. The way I see it now, it might be in the range of $20-$25 a barrel, even though it is far to the north. Location markup is not really that important here. And then the huge subsea spread, yes, that impacts cost. But remember, it will be done over several seasons, meaning you'll come in production with a smaller spread and then add on wells as you move forward. So that is actually quite beneficial even to the NPV and the break-even, obviously. Buybacks. Buybacks again. Yeah. So Mark, obviously, my answer is that we don't need to do anything in terms of it all depends, of course, on how the world develops. But the way that we view this is that the ambition of increasing by a minimum of 5% per year through the investment cycle here, that goes up until 2028. And then, as I said, buyback is part of the toolkit, depending on financial capacity and how the macro environment develops, etc. And then in terms of how we think about dividends post-debt, obviously, will depend on the business profile of the company and also the, call it, the financial capacity at that point in time. So buybacks is always a discussion that comes up with discussions with US analysts and also investors. And we are mindful that some think that that's a good idea for us to do, given also recent share price performance, while others think that it's better to invest in or distribute via dividends or invest in the portfolio. Thank you, Mark. Thank you very much. Let's move on. Then the final question is a follow-up from James Carmichael from Berenberg. Yes. Thanks, Jonathan. Thanks for a quick follow-up. Just a couple of additional ones. Firstly, just on Ula, you mentioned that you expect the concept select for the decommissioning plan there to be taken fairly soon. I'm just interested if you can put any sort of initial numbers around that and whether any of that will sort of fall before the COP in 2028. I guess we should expect an uptick in decom versus the recent run rate, which has always been fairly low. And then just on tax, you mentioned somewhere in there that we're going to be changing to 10 installments a year from six. Just wondering if that will have any impact on the sort of usual tax basis that we see in Norway. Yeah. So let's talk about Ula first. So the only CAPEX number that will be on Ula pre the COP in 2028 is basically related to studies. The way we are actually looking at this right now is that most of the work will be carried out post 2028. And then mainly due to the fact that we need the rigs to drill producers and injectors on the ongoing field developments and not really related to allocation of capital. The CAPEX is included in the numbers we have shown today. And as maybe another tidbit of information, if you remember back to the P&A campaign we did on Valhall, we have actually demonstrated that to be able to pool all of this together creates a lot of learning opportunity and therefore a much reduced P&A cost compared to just slotting it into the well schedule. So we prefer actually to look at this as a one campaign post 2028, do all the wells in one campaign as efficient as possibly we can. And then I think the Valhall reduction number was in excess of 50% based on the ingoing estimate. So that's how we think about Ula. And then tax installments. Yeah, yeah. So good catch. So we included some comments on that in the presentation. Of course, it's been fairly well communicated by the authorities as well. And then there are some notes around that. And obviously, if anybody wants more details, you can follow up with the IR team. But just to be clear, so we're going from six installments to 10. And that means that the deviations between the quarters will be smaller compared to what they've been in the past. So I think for your quarterly modeling, this is something to be mindful of. But it does not impact the total taxes paid and not the total taxes paid within the six-month period, so the first and the second half of the year, but between the quarters. So less averaging over quarters, James, that's probably the net effect. Great. Thanks so much. All right. That was the final question, Karl. So now it's excellent. So thank you, David. Thank you, Kjetil. And thank you to the entire team who's been behind this update today. And thank you to everybody who's been listening. And particularly, thank you to those who asked questions to David and myself. And then obviously, I hope to see you all on the road pretty soon. There's quite a lot of investor relations activities and road shows coming up. And I do hope to see you in person. Thank you so much and have a great day.