Aker BP ASA (AKRBP) Q4 FY2025 Earnings Call Transcript & Summary

Good morning, everyone, and welcome to our presentation of Aker BP's Fourth Quarter and Full Year 2025 results as well as our annual strategy update. I am joined today by CFO, David Tonne, and you will also hear from a few others in the team as we go along. Our agenda today has 3 main parts: First, a review of our operational and financial performance in 2025; second, our strategy update and the priorities that will guide us in the years ahead. And finally, as usual, a Q&A session. Let me provide the key highlights for 2025. We delivered strong cash flow from operations, supported by consistently high production efficiency across the portfolio. Our major development projects progressed as planned and remain on schedule for start-up in 2027. It was an outstanding year for exploration as we participated in the 3 largest discoveries on the NCS and added around 100 million barrels of resources. We maintained an industry-leading cost and emissions performance. And financially, we kept a clear focus on shareholder returns while protecting the balance sheet and preserving financial flexibility. With that, let's look at '25 performance in a bit more detail. Full year production for 2025 averaged at roughly 420,000 barrels per day, at the top end of our initial guidance a year ago. The outperformance was broad-based and the production efficiency landed at 96%. I would particularly like to highlight the contribution from Alvheim, where we reallocated processing capacity to Tyrving through a commercial arrangement. This added flexibility and supported production in the first half of the year. Johan Sverdrup continues to be our single largest contributor to production. The field delivered strong and stable volumes through 2025, supported by excellent reservoir quality, high regularity and very low operating costs. Last year, we took several steps to strengthen the long-term production profile. The retrofit multilateral campaign is progressing well, the second well is now on stream, and the third is being drilled. There has been a lot of attention recently around Equinor's comments on expected 2026 production, indicating a decline of more than 10% from last year. This should not come as a surprise. The field has produced around half of its reserves. And like any field in this phase, production will, of course, gradually decline over time. This expected decline has been reflected in our company guidance throughout. And we are taking active measures to manage this decline. For 2026, we plan to drill 6 infill wells from the drilling platform, along with a subsea campaign of 3 additional infill wells. We will also drill an appraisal well on the north flank, Tonjer, to assess the potential for a new template in that area. And then we have Phase 3. This subsea expansion will add 2 new templates and 8 wells. The project was sanctioned last year and is progressing as planned with fabrication ongoing at several sites. Drilling of the Phase 3 wells is set to begin towards the end of 2026 and start-up is expected in the fourth quarter of 2027. Overall, Johan Sverdrup remains a world-class asset that will continue to deliver high-value barrels for many years to come. We maintain an industry-leading cost level with production cost of $7.3 per barrel, essentially in line with our guidance of around $7. This reflects strong production efficiency, a firm cost discipline, effective execution of maintenance activities and a constant focus on the operational performance. Our emissions intensity was 2.8 kilograms of CO2 per barrel, among the lowest in the industry, and we delivered solid safety results with a low and stable TRIF and SIF. Keeping our people safe will, of course, always be our top priority. 2025 was also a very active year for our field developments. We often get questions about what this activity really look like, what our teams are doing, how we work on folds, and what scale that lies ahead of us in the coming years. So instead of walking you through every single task, I thought we'd just show you. This short video offers a quick glimpse into the pace, the scale of the activity across the field developments last year. [Presentation]

We will return to the 2 largest projects later in the presentation, but let me say a few words about the smaller developments, the tieback projects that are also delivering high value. In short, they are performing exactly as they should. Solveig Phase 2 tied back to Edvard Grieg came on stream last week, on time and on budget. Symra, which will be tied back to Ivar Aasen, remains on track for start-up later this year. And the Skarv satellites are progressing so well that we now expect first oil already in the fourth quarter, more than 6 months ahead of the original plan. 2025 was a breakthrough year in exploration. We participated in the 3 largest discoveries on the NCS and added around 100 million barrels net to Aker BP. At Kjottkake, we worked closely with DNO, combining our subsurface insight and fast-track development approach to rapidly unlock and mature discovery. At Omega Alfa near Yggdrasil, we pushed the technical frontier with advanced geosteering, wired pipe technology and long horizontal drilling. This enabled real-time reservoir mapping and turned a multi-target well into one of the largest NCS discoveries in a decade. Lofn and Langemann is also a highly promising discovery, which was enabled by ocean bottom nodal seismic, where sensors are placed on the seabed to provide more precise geological data than traditional surface seismic. We will return to the topic on exploration later. Now the 2025 numbers.

Thank you, and good morning to you all. As Karl just outlined, 2025 was a year of strong operational performance, providing a solid foundation for continued delivery of our value creation plan. Sustained high production and low operating costs, combined with a relative stable commodity price environment and immediate tax deductions for investments resulted in a record high operating cash flow of around $7 billion. Our development projects remain on schedule for start-ups this year and the next. In fact, the Skarv satellites have now been accelerated into 2026. At the same time, throughout 2025, our 2 largest development projects have increased in size, both in terms of total investments, but also the resource base and expected future production. We will return to this later. During 2025, we have taken several proactive measures to further strengthen our financial flexibility and Aker BP enters 2026 in a strong financial position with a balance sheet with low leverage and ample liquidity. Lastly, in accordance with our ambition, we increased dividends by 5% year-over-year. So with that backdrop, let's turn to the 2025 financial results. Earnings ended at $2.8 per share compared to $3.5 in 2024. Importantly, we delivered a strong operating cash flow of $11 per share, up from $10 the year before. This provided a solid foundation for the $2.52 per share in dividends we paid, while also covering most of our growth investments. And finally, we closed the year with a continued low leverage ratio of 0.6x net debt to EBITDAX. Zooming then in on a few key points from the fourth quarter. Production in the quarter averaged 411,000 barrels per day. With an overlift position of 20,000 barrels per day, more or less reversing the underlift from the third quarter, net sold volumes ended at 431,000 barrels per day. Realized hydrocarbon prices averaged $63 per barrel of oil equivalent with realized oil prices as normal, slightly above Brent. Operating costs came in at $7.9 per barrel produced compared to $7.6 in Q3. The increase mainly reflects the phasing of maintenance activities and production mix. Throughout 2025, we have, as expected, seen a stable increase in production cost per barrel, driven by the decline in production. This has been amplified by the weakening of the dollar against the Norwegian kroner, starting the year above NOK 11 and ending around NOK 10. As mentioned, operating cash flow for the full year was record high. Looking at the quarterly pattern, cash flow before tax payments and working capital movements remained fairly stable through the year. With tax now paid in 10 monthly installments, quarterly cash flow will be less volatile going forward, all things equal. Investments in the fourth quarter were $0.1 billion higher than the 2 preceding quarters, with the main driver being the major development projects. The combination of 3 tax installments, a small working capital increase and higher CapEx resulted in a negative free cash flow of $427 million for the quarter or minus $0.68 per share. Let me also comment on the impairments this quarter. As you can see from the income statement, we recognized impairment charges of $944 million in the quarter. These relate to technical goodwill on Johan Sverdrup, the Valhall and Alvheim areas as well as other intangible assets at Valhall. The main driver this time is lower forward prices for oil and gas at the end of the fourth quarter compared to the end of the third, which reduces the recoverable value in the accounting tests. As a reminder, technical goodwill is an accounting effect from earlier acquisitions. Because this goodwill is not depreciated under IFRS, we must test it every quarter. And all else equal, as we continue producing from the assets where goodwill was allocated, we should expect noncash impairments over time. When price assumptions move, that amplifies the effect. Since impairment of technical goodwill has no tax deduction, the charges flow straight through the income statement and result in a high reported tax rate. For the quarter, the effective tax rate ended at 137%, and this is entirely driven by the impairment effect. If we adjust for these noncash items, earnings per share would have been significantly higher and the tax rate would have been much closer to what you should normally expect. And as always, for those of you who want a deeper explanation of technical goodwill and how impairments work in our accounts, I recommend the short video available on our investor website. Moving on to the balance sheet and recent developments in our financial position. Building financial capacity and ensuring access to capital is a continuous process for us. Over the past years, we have completed several successful bond transactions, which have strengthened our financial flexibility and pushed our debt maturities well beyond the start-up of our major field developments. In October, we continued to capitalize on favorable market conditions by issuing $1 billion in 10-year senior notes maturing in 2035, with the tightest credit spread on a 10-year note ever achieved for Aker BP. To me, this once again confirms that the U.S. bond market and its high-quality institutional investors share our confidence in the long-term outlook for oil and gas, the strength of the Norwegian Continental Shelf and in Aker BP's strategy and value creation potential. Also in October, we refinanced our bank facilities, a total of $3.2 billion with maturities up to 5 years with options that could extend final maturity to 7 years. This refinancing replaces the previous facilities that were set to mature in 2026. As shown in the chart on the left, net interest-bearing debt increased to $6 billion by year-end. At the same time, tax payables came down significantly to $1.1 billion. In practice, this means that half of the debt increase was driven by the reduction in taxes owed to the state. Our leverage ratio remains low, but as expected, given the current oil price environment and our investment program, it ticked up to 0.6x net debt to EBITDAX at the end of the quarter. Total available liquidity stands at $5.9 billion, where $2.6 billion is cash or equivalents and the rest is our undrawn bank facilities. Now to round off, let me briefly recap how our 2025 deliverables tracked against our guidance. We started the year with a production guidance of 390,000 to 420,000 barrels per day. As we progressed through the first half, performance was very strong across several fields, particularly from Tyrving in the Alvheim area, which derisked the lower end of the range. We, therefore, raised the bottom of the guidance at our second quarter presentation. Momentum continued through the summer with consistent high performance across the portfolio and importantly, a Valhall with no chalk influx issues for the first time in many years. This gave us the confidence to lift the guidance again in Q3 to the most recent guidance range of 410,000 to 425,000. For the full year, production in the end averaged at 420,000 barrels per day, at the very top of our original range. On production cost, we guided around $7 per barrel and ended at $7.3. The main driver for ending in the higher end was the weakening of the U.S. dollar versus the Norwegian kroner, moving, as mentioned, from above $11 to around $10 through the year. Underlying costs were in line with expectations and with like-for-like foreign exchange rates, production cost would have ended below $7 per barrel. Turning to CapEx. As many of you will remember, we increased our 2025 estimate to around $6.5 billion in July. We ended nearly 8% above that, close to $7 billion. The increase was mainly driven by 2 factors: good progress, but also higher spend on the PWP-Fenris project and the same currency effect that impacted production costs. The foreign exchange impact was, however, partly offset by our currency hedging program, which in the third and the fourth quarter delivered realized gains of $13 million, equivalent to a CapEx reduction of around $75 million. Exploration and abandonment spend came in as guided, close to $500 million and $100 million, respectively.

With 2025 behind us, it is time to look ahead. And before we turn to Aker BP's strategy, let me briefly step back and look at the broader strategic context, which really, in my mind, comes down to 2 questions. First, will the world continue to need oil and gas? And second, does the Norwegian Continental Shelf and Aker BP have a role to play. On the first question, global oil demand continues to be much more resilient than many expected. Much of the growth comes from aviation, petrochemicals and expanding economic sectors that continue to depend on oil, while road transportation remains the single largest source of consumption. Our market analysis points to a continued growth in the global oil demand at least to 2035. The energy transition is accelerating, but the global demand for energy is growing even faster. We are still adding new sources of energy, not replacing the existing ones. We will, therefore, rely on hydrocarbons throughout the transition and the world is better off sourcing these barrels from lowest emission producers. At the same time, natural decline in existing fields removes a large number of barrels in supply each year, which means substantial new investments is required just to keep the market in balance. If we step back from the short-term volatility, the oil market remains structurally tight. On the second question, let me start by saying that the Norwegian Continental Shelf is a fantastic place to be for an oil and gas company, not only because of the resources beneath the seabed, but also the environment above it. We operate within a stable and predictable regulatory and fiscal framework supported by high standards for safety and emissions. And we have a world-class supply ecosystem that drives innovation and raises the performance for the entire sector. According to the Norwegian Offshore Directorate, Norwegian oil and gas production is around its peak today and is projected to decline unless decisive action is taken. The Directorate outlines 3 scenarios towards 2050. In the high scenario, which means significantly higher production and creates significantly greater value for the society, 3 things must happen. First, Norway needs sustained exploration activity that delivers a large number of commercially viable discoveries, both near the existing infrastructure and in the less mature areas like the Barents Sea. Second, we need rapid technology development to increase recovery both from existing fields and to unlock resources that are smaller and more complex like tight and HPHT reservoirs. And thirdly, we need a continued industry commitment to invest in exploration, in developing discoveries and in improved recovery across the shelf. If we deliver on these priorities, the high scenario is certainly within reach. Norway can continue to develop its resources, contribute to Europe's energy security and create sustainable, substantial long-term value for the society. This is Aker BP's clear ambition and delivering on it will require technology, speed and new ways of working, areas where Aker BP already stands out. For years, we said digitalization would reshape our industry. Today, that shift is no longer theoretical. It is here, and Aker BP has a unique advantage, a long history of forward-leaning digital ambitions, combined with a scale that lets us move fast. Over the past decade, we haven't just built digital tools. We've built a data connection that connects the whole company, high-quality, structured real-time data. On the top of that sits a future-fit digital ecosystem that allows us to integrate, automate and optimize across exploration, drilling, project and operations. This foundation is what makes everything else possible, including the growth we are aiming for. We started out by improving analog work processes. Then we digitalized them. And now we are entering a stage where the entire workflows themselves are being reconstructed. Artificial intelligence collapses in traditional processes and gets us to decisions in a fraction of the time. We're already seeing the impact across the business. In exploration, artificial intelligence is enabling earlier and better decisions. In drilling, wired drill pipe, long horizontals and advanced geosteering is delivering world-class performance. And at Yggdrasil, digital twins, autonomous systems and condition-based maintenance are turning remote and low-manned operations into reality. And finally, across operations, AI agents are cutting troubleshooting time, improving uptime and freeing our people to focus on higher-value decisions. But this is not experimentation. It's a capability. A capability that strengthens our competitiveness, increases our pace, lowers our cost per barrel, and supports the growth journey ahead. It is a differentiator that helps us move from discovery to first oil faster than ever before and do so safely and predictably. And this is why we are so confident about the road ahead, because we're not starting now. We are scaling on 10 years of investment, hard-won experience and a data foundation that many talk about, but few actually have. The NCS now needs a step-change in productivity. It is, in fact, a race to deliver faster, safer and at a lower cost. And the companies who manage that will shape the future of the shelf. Aker BP is pulling ahead, and I can assure you we do plan to stay here. Before we move on, let's hear a brief external perspective.

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

Another cornerstone of our competitiveness is the Aker BP alliance model. Over the past decade, our alliances have helped us remove waste, use resources more efficiently, reduce drilling risk and build stronger, more adaptive team together with our suppliers. This is what has enabled us to reach what we always call as good as it gets in several parts of our delivery chain. But as I just said, the NCS is changing and our alliance model must evolve with it. The developments we are planning for the next decade require even tighter collaboration, more repeatable solutions and far deeper digital integration than ever before. So we are now taking the next step. We are developing the next generation of alliances where our partners will work even more closely with us, supported by shared data, standardized solution and performance-based contracts. And the goal is simple: deliver faster at lower cost and with higher quality and stay ahead as the NCS becomes more competitive, both for us and our alliance partners. Our drilling teams show how this has come together in practice. We are systematically removing inefficiencies through technology, scale and continuous improvement. And as this chart shows, we are the most efficient operator in the sector. New technology and innovations such as wired pipe, conductor-less wells, horizontal exploration laterals and dual penetration enabled shallow water drilling are driving step changes in speed, data, quality and emissions. At Yggdrasil, these innovations are expected to deliver around 20% higher drilling efficiency compared to the average, freeing up an entire rig year annually. The results are more value, more prospects that become economically viable and materially lower emissions per barrel. This chart shows our production outlook to 2030. We expect to reach around 525,000 barrels per day in 2028, driven by the delivery of a major project now under execution. Beyond 2028, our ambition is unchanged, to sustain production around 500,000 barrels per day into the 2030s. And compared to last year, the foundation behind that ambition has strengthened. The business plan beyond 2028, that is the dark blue area on this graph, has grown. This reflects additions across the portfolio, including Kjottkake, identified upsides in the PWP-Fenris area, more tiebacks in the Skarv area, and better reservoir performance in the Alvheim area. Together, these additions have almost closed the gap to 500,000 barrels per day in 2030, and they give us a stronger and more diversified production base as we enter the next decade. Looking further ahead, 3 levers will shape our post-2030 trajectory. First, the discoveries that are already in our portfolio, including Wisting as well as a broad set of IOR and tieback opportunities around our hubs with the recently discussed Omega Alfa as an addition. Second, a continued active exploration program supported by artificial enabled subsurface tools and innovative drilling methods that raises success rates. And third, selective M&A, strengthening our long-term portfolio and accelerating value creation. Together, these levers position Aker BP to deliver sustained, profitable production way into the next decade. But first, let's look at the major projects, Yggdrasil and PWP-Fenris, which are the largest building blocks in our growth story right now. And let me start with Valhall PWP-Fenris, because this project is reshaping the future of the Valhall area. We are, in fact, redeveloping Valhall with a new production and wellhead platform that expands capacity and extends the life of the field. At the same time, we are adding gas processing capability that makes it possible to tie back Fenris, a gas discovery, which is an integrated part of the development. The concept is straightforward, a new production and wellhead platform called PWP at the Valhall field center and an unmanned installation at Fenris tied back 50 kilometers to Valhall. The jackets for both platforms are now in place. The Fenris drilling campaign has been completed and drilling at Valhall has started. Construction of the topsides are progressing at Stord and Valhall. To ensure that we maintain a strong momentum in this critical phase and to secure start-up in 2027, we have strengthened the resourcing at the yards. These measures give the teams capacity they need to keep PWP on topside on track for sail away from Stord in the third quarter this year. And on the resource side, the development is becoming even more attractive. After an excellent drilling campaign at Fenris, we are adding a fifth well there. And at Valhall, we have added 4 more wells to the plan. In total, these wells are expected to increase recoverable volumes by 30 million to 35 million barrels net to Aker BP, an increase of around 17% from the initial estimates and a good example of how big fields get bigger. With this, the net investment estimate for the project is now roughly $7 billion, about $1 billion higher than previously. Most of this reflects the actions we are taking to keep the schedule on track, while about 1/3 is linked to the additional barrels. In short, yes, the investment estimate has increased, but so has value. The additional wells are adding material resources, the long-term area potential is improving, and we are still on schedule for first production in 2027. Yggdrasil is not only our largest ongoing development. It is a defining example of what Aker BP stands for. It brings together technology, leadership, our alliance model, execution capabilities and our commitment to delivering low-emission barrels at scale. The Yggdrasil project is progressing steadily towards startup in 2027. The jackets are now installed at both Hugin A and Munin and the drilling campaign is underway. And topside assembly is progressing on plan at the yards in Stord, Haugesund and Valhall. In Q4 this year, we are planning to install the Hugin A topside offshore, a major and very visible milestone for the project. But that's only a part of the story. 2026 will indeed be an exceptionally busy year for Yggdrasil. [Presentation]

In many ways, Yggdrasil is the blueprint for Aker BP's future and a glimpse of the future NCS. And it's not just the development concept that points forward. The resource potential around it does as well. Big fields tend to grow and Yggdrasil provides a strong platform for continued expansion. A great example is Omega Alfa, the major discovery we made this summer. It added more than 100 million barrels gross to the Yggdrasil area and moved us significantly closer to our 1 billion barrel ambition for the area. We also see further upside, and we expect to return with more exploration drilling in 2027. In the meantime, we also have an exciting exploration program lined up for 2026. If I were to highlight one area in particular, it would be our campaign at Utsira High. We start with Tonjer in the Johan Sverdrup unit. It is maybe not the largest project, but it carries a relatively high probability of success. In the second quarter, we will drill Svarteknippa located near Solveig and Edvard Grieg. And this well in together with Freke North later in the year, represent a natural follow-up to the Lofn and Langemann discoveries, aiming at further maturing this play and possibly extending the proven trend. In the same area, we also will drill the Symra Phase 2 appraisal well. Together, this campaign represents a significant opportunity, and it sits at the core of our strategy, how to grow the resource base around our existing hubs. In the Northern North Sea, I would also probably highlight the Alpehumle well planned for this summer. Located north of Gjoa, it carries substantial value potential and targets the same play concepts as the nearby discoveries such as Cerisa, Ofelia and Duva. But exploration is not just about the next well or the next campaign. It's about how we build long-term advantage. And the way we explore is changing. It's driven more by technology, data and entirely new ways of working. So let me show you how we at Aker BP are reshaping the exploration workflow. What used to be a slow and sequential process is now becoming a fast, data-driven and technology-enabled, allowing us to test more ideas, reduce risk and make better decisions earlier. First, we are successfully using real-time exploration drilling. Horizontal geosteering, wired drill pipe and ultra-deep resistivity tools gives us real-time insight into the reservoir. Decisions that once took days now happen in seconds. We can test multiple targets in a single run, turning what might previously have been a dry well with shows into commercial discoveries. Secondly, we are gaining massive AI-powered subsurface insight. Our in-house developed AI tools analyze huge amount of geological and seismic data in minutes, work that would normally have taken days or even weeks. This gives us better prospect selection and frees up our experts to focus on areas where human judgment really matters. An excellent example is in the 2025 APA licensing round. Here, AI really supercharged how we work. Instead of weeks of manual screening, document searches and draft iterations, we use our in-house AI assistants to prescreen data, highlight geological features worth a closer look and pull forward relevant insights from past applications and analog field. On top of that, AI-driven drafting tools help us speed up the writing itself. This enabled our geoscientists to evaluate opportunities faster, improve the geological understanding and deliver a stronger overall application. The productivity gain was tangible and the highly successful APA results reflected it. And this is what AI means for us, practical tools that lift speed, increase quality and the confidence in our decisions. And then thirdly, high-resolution ocean bottom nodal seismic provides a step change in imaging quality, reducing uncertainty, improving well placement and derisking prospects, particularly in the mature areas where this clarity matters most. Lofn and Langemann is a very strong example of the value of ocean bottom nodal seismic. So what does all this mean? Well, in short, these innovations compress traditional workflows into something faster and more powerful. We explore with higher accuracy, higher confidence and lower cost, and the impact is already visible in discovery such as Omega Alfa, Kjottkake, and Lofn and Langemann. But this mindset doesn't really stop at exploration. It's the same way we are rethinking workflows that are now shaping are mature and we develop our discoveries faster, leaner and with far better insight. By working as one team across exploration, subsurface and project, we are developing the next generation of project in a far more efficient way.

For many years, Aker BP has systematically built strong and proven field development capabilities through our alliance model, the adoption of new technologies and a relentless push on digitalization. Looking toward the 2030s, the NCS is changing. The resource potential remains significant, but the discoveries are smaller and the reservoirs more complex. To stay ahead, we must once again raise the bar, compress time lines, improve efficiency and turn marginal resources into profitable barrels. And we must keep pushing the boundaries of technology and innovation to unlock the more complex reservoirs and developments that will define the next decade. At Aker BP, we are now moving to the next level, reinforcing next-generation field developments along 3 fronts. Standardization and proven technical solutions have long been an important part of our projects, reducing complexity and enabling continuity. We are now advancing this approach by scaling standardized, leaner and more repeatable solutions in engineering, well design, modular layouts and equipment. We shorten time lines, lower cost, improve predictability and build portfolios of projects where learning compounds and accelerate performance. At Aker BP, an integrated end-to-end data flow is becoming the backbone of how we work. Instead of long linear and requirements heavy processes, we use an argue-in approach with rapid iteration, sharper trade-offs and early clarity on value. Rethinking workflows from exploration to first oil and maturing subsurface and development concepts efficiently in parallel, improve value, decision quality and speed. And with one shared data foundation, we can automate workflows and scale AI. Our proven alliance model built on shared objectives, aligned incentives and true co-development with our core suppliers remains a defining pillar of Aker BP. And as we shift to fully data-driven integrated workflows from exploration to first oil, we are further enhancing how we work together as one integrated team across subsurface projects and our suppliers. We have what it takes, a strong foundation, proven capabilities and the mindset to transform at pace. For next-generation projects, our ambition is clear, to halve the time it usually takes from discovery to first oil on the NCS and drive cost efficiency at similar magnitude, and we are already seeing the results. Take Kjottkake. The discovery was made in March 2025. Shortly after, we increased our ownership by acquiring Japex stake, and we recently became the operator for the development phase. We moved quickly to define a viable tieback concept, subsurface projects and partners, worked in focused sprints, capitalizing on our proven alliance model, simplifying decisions and removing waste in the process. We are now on track for first oil in early 2028, 3 years after discovery. That sets a new pace for the NCS. By developing the next generation of projects faster and far more efficiently, we will continue to maximize value around our hubs and innovate to unlock new plays, turning the increasingly marginal and challenging resources into profitable barrels. Take Skarv. through developments like Aerfugl and Skarv Satellites, we have already doubled recoverable volumes. Recent discoveries add further upside, and we aim to extend production on Skarv well into the 2040s. Data-driven workflows combined with standardized and lean solutions and close collaboration with our alliance partners allow us to deliver our portfolio of infill wells and subsea tiebacks faster at lower cost and with greater confidence. On Valhall, recoverable resources have increased sixfold since start-up, and we still see significant potential. With PWP-Fenris, we are now turning Valhall into a long-term hub for oil and gas in the Southern North Sea. And with decades of experience from continuous tight reservoir development on Valhall, combined with a high pressure development on Fenris, we have already taken important steps toward unlocking even more challenging reservoirs across NCS, such as Victoria and Warka, one of the largest undeveloped gas discoveries on the NCS with around 250 million barrels of oil equivalent recoverable. Technically challenging, tight and HPHT, but a pivotal building block for turning the large tight reservoir potential on NCS into profitable barrels and opening a new play type beyond our current portfolio. Awarded in January, we are already progressing at pace, qualifying technologies, capturing scale effects and improving production rates. The work we are doing today defines Aker BP's capabilities for the decade ahead. It positions us to continue developing the NCS responsibly and competitively. And it strengthens our ability to deliver efficient and low emissions productions for decades to come.

The Kjottkake story is not only about exploration success and fast project execution. It also highlights an important point about M&A, our third lever for sustaining production into the 2030s. It shows that with the right partnership, the right ownership structure and fast aligned decision-making, we can unlock substantial value. Our approach to M&A has been consistent for more than a decade, value-driven, grounded in sound industrial logic and focused on efficient integration, never scale for its own sake. Some examples include the acquisition of Hess in Norway, strengthening our position in the Valhall area and unlocking new growth opportunities. King Lear added new high-quality resources and paved the way for Fenris. And the combination with Lundin Energy, transforming our portfolio, bringing Edvard Grieg into Aker BP and increasing our stakes in world-class assets such as Johan Sverdrup and Alvheim, creating a more robust foundation for the highly value-accretive developments now nearing completion. This track record reflects disciplined capital allocation, deep technical understanding on the NCS and a long-term mindset. We will continue to pursue opportunities, but only where we see a clear strategic fit, compelling economics and the potential to create real value for our shareholders.

We are now more than halfway through our 6-year value creation plan launched at the beginning of 2023. It's a plan designed not only to deliver value-accretive growth well into the 2030s, but also strong cash flows and substantial distributions to shareholders along the way. We are progressing well and entered 2026 with a strong financial position, expecting 36% production growth over the next 2 to 3 years and have a lot of exciting opportunities to create significant shareholder value beyond that. And with that as a backdrop, our capital allocation priorities remain firm. Our first priority is to ensure we always have sufficient financial capacity. That means maintaining a strong balance sheet and ample liquidity, so we can manage volatility, fund our investment program and preserve strategic flexibility. Second, we invest to create value. We continue to allocate capital to projects with strong returns, low breakevens and robust cash generation. Our tieback projects in the Eiga and Skarv area will be completed in 2026, and we continue to invest in our major development projects with start-up in 2027. In addition, we mature and sanction new developments such as Johan Sverdrup Phase 3, the Kjottkake discovery and high-return infill wells to maximize shareholder value. And third, we return the value we create to our shareholders. Our dividend framework provides consistency and predictability. And as our cash flows grow, we remain committed to distributing that value back to investors. These 3 priorities guide every capital decision we make. And as I've earlier today already covered the financial capacity part, let me turn to our investment program. As Karl has already covered, our development projects are progressing according to schedule. Over the past year, we have updated our investment plan to reflect the latest cost estimates and to include new highly profitable projects. As you can see in the chart, we are now past the peak investment year in our 2023 to 2028 value creation plan. 2026 will still be a CapEx-intense year, but as the major field developments move towards start-up next year, CapEx will come down sharply. For 2026, we now expect CapEx in the range of $6.2 billion to $6.7 billion. That is roughly $0.5 billion higher than previously indicated, driven by mainly 3 factors. Currency effects, a stronger Norwegian kroner versus the U.S. dollar increases the CapEx when measured in dollars. This accounts for roughly $200 million of the increase. New projects, around $100 million, mainly related to Kjottkake. And lastly, increased cost to safeguard the schedule for Valhall PWP-Fenris. For 2027 and 2028, we have included new growth investments compared to last year. The most notable additions are Kjottkake and the PWP-Fenris upside program, which includes 5 additional wells. Together, these investments add more than 50 million barrels net to Aker BP from 2028 and onwards. Most of our investments in 2026 and '27 qualify under the temporary tax rules, providing an 86.9% tax deduction. From '28 and onwards, investments get 78% deduction in line with the standard petroleum tax regulation in Norway. As most of the deductions are realized in the year of investment, it is important to also look at the actual after-tax cash flow impact. And finally, as already discussed, because more than 2/3 of our investments are denominated in Norwegian kroner, our U.S. dollar estimates are sensitive to currency movements. And to manage this, we have proactively hedged 70% to 85% of our planned after-tax NOK expenditures for 2026 and 2027 at an average U.S. dollar-Norwegian kroner rate between NOK 10.5 and NOK 11. The financial effects of this hedging do not impact reported CapEx. They are recognized as financial items. And as shown in the note to the balance sheet, our current currency derivatives positions were valued at approximately $109 million at year-end. These positions relate to the hedging of our planned Norwegian kroner expenditures. With a 22% tax rate on currency derivatives, the after-tax value is around $85 million. To put that into context, in value terms, this corresponds to roughly $650 million in lower CapEx across 2026 and 2027. As we ramp up production from our new projects and CapEx starts declining, free cash flow will significantly increase over the next 3 years. By the end of 2028, we expect to have generated up to $12 billion in cumulative free cash flow on how oil and gas prices develop. In turbulent times, resilience matters. We have built financial strength to withstand volatile commodity markets and our metrics remain robust across most plausible oil price scenarios. Assuming a continued 5% annual increase in dividends, our leverage stays comfortably below our internal threshold of 1.5x and well within the bank covenant of 3.5x. Even in a prolonged $50 oil price environment assumed from the start of 2026, our modeling shows that leverage would only exceed 1.5x at the end of 2026 before declining again through 2027. So in summary, our value creation plan is on track, and we have both the capacity and the resilience to fund our investments and deliver attractive shareholder distributions in the years ahead. And when it comes to shareholder distributions, we stick to our guiding principle that the dividend should be resilient and reflect our financial capacity through the cycle, taking into account both our long-term outlook and our credit profile. As we enter 2026 with a strong balance sheet, a high underlying cash generation from our producing assets, we have a solid foundation to stay true to our ambition of growing the dividend by at least 5% per year throughout this investment period to 2028. We are, therefore, proposing a 5% increase for 2026, which takes the total dividend to approximately $2.65 per share paid quarterly. Now let me round off with a few comments on our 2026 guidance, starting with near-term tax payments. The tax payments in the first half of the year reflect taxes accrued in 2025. We expect tax payments around $300 million and $450 million in Q1 and Q2, respectively. For the second half of 2026, the tax payments will be set around midyear based on an updated full year estimate. In this chart, we illustrate what those payments may look like under different oil price scenarios. One clear takeaway is that with an oil price below $70 for the year, tax payments in the second half would be limited due to our investment program. This is a key feature of the Norwegian tax system. It provides resilience to market volatility when investing in profitable growth. And finally, the guidance on other key metrics for 2026 is as follows: For 2026, we expect average production of 370,000 to 400,000 barrels per day. These estimates are based on P50 bottom-up assessments across our portfolio, and the range reflects the simulated uncertainty in those forecasts. The reduction from 2025 is driven by underlying decline in several fields, partly offset by start-ups of new subsea tiebacks in the Eiga and Skarv area. Operating expenses are expected around $8 per barrel produced. This is up from the 2025 average of $7.3 per barrel, driven by the weakening of the dollar against the Norwegian kroner and lower production year-over-year. As already discussed, we estimate total CapEx for 2026 to come in between $6.2 billion and $6.7 billion, down from $7 billion in 2025. Abandonment expenditures are expected to be broadly in line with last year at around $100 million, with plugging and abandonment of old wells on Valhall as the main driver. Lastly, 2026 is set to be another active exploration year with 12 wells currently planned, including seismic and early phase maturation. We expect total exploration spend of around $400 million. And with that, I'll hand it back to Karl for some final remarks before we move on to the Q&A session.

Thank you, David. Aker BP delivered a strong performance in the fourth quarter and throughout 2025, achieving low production cost, low emissions and production at the high end of our originally guided range. Our major projects progressed as planned and remain on schedule for start-up in 2027. The investment estimates have been increased for several reasons, not at least that additional barrels have been added to the projects. The ongoing tie-in projects have accelerated start-ups and all are now starting up in 2026. 2025 was an outstanding year for exploration as we participated in the 3 largest discoveries on the NCS and added around 100 million barrels of resources. We have a clear and well-defined plan to sustain production above 500,000 barrels per day from 2028 with even greater ambitions beyond that, amongst other, assisted by the increased volumes in the Yggdrasil area and the PWP-Fenris area. Aker BP acknowledges the new reality on the NCS. We are preparing for the future by rethinking how we mature and develop our discoveries faster, leaner and with far better insight. By working as one team across our internal functions and the broader ecosystem, we will deliver the next generation of projects in a significantly more efficient way. And we remain committed to delivering shareholder value, including a planned 5% increase in base dividends for 2026. We will now take a short pause before opening the Q&A session. And to participate, please use the Teams link on the webcast page. And if you prefer to listen only, please stay tuned. We will resume in 1 minute. [Break]

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

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

Might be, but we hear nothing.

Sorry, Teodor, we have a small technical issue.

Okay, you can't hear us?

Now, we can hear you.

So I guess I'm limited to 2 questions, although Kjetil didn't say that, but I'll limit myself to 2 questions. First one, you showed this beautiful graph on production going forward, where you show flat production into the 2030s. Var Energi tells the same flat production and Equinor also tells that production will be flat until 2035, while the Norwegian Petroleum Directorate, they believe or the base case is substantial decline. So who is correct? If you just could shed some light on your thoughts there, that would be very useful. And also maybe how Wisting comes into play into the guidance of flat production going forward. So that's the first question. Second question that is on dividends. You increased dividend by 5%, as you have indicated, as long as oil price stays above $40 per barrel. But how should we think about this after Yggdrasil first oil? Should we expect you to change that guidance or increase it? I assume that CapEx profile will look very different after Yggdrasil first oil. So that's my 2 questions.

Thanks, Teodor, and thank you for limiting yourself to 2 questions. Even though they were very fundamental questions, I'll try to be a little bit brief. There is no doubt if you look at the Norwegian Continental Shelf and, call it, the outline of the different companies and their inherent strategies as you just very succinctly presented that there will be a challenge on the Norwegian Continental Shelf. And this is the very precise background for the presentation that Marte gave a bit earlier today, our long-term focus on AI and time compression and how we think about alliance models to actually create a significantly more time-compressed field development. Combine that with our efforts on exploration, not least the delivery we did last year with 100 million barrels, but also the APA awards this year, we have, over time, built a significant backlog, both of prospect leads, discoveries and very early phase projects. So my view on this is, yes, the overall Norwegian Continental Shelf is likely to decline over time. But I can assure you, we've been prepared for this for a long time, and we will do whatever it takes to lead that game. And then I think there's a final point, Aker BP, because of a bit of a later startup of our projects, starting up in 2027, we actually have a little bit of a less challenge than some of the other companies that you referred to managing that decline into the 2030s. But it is a key point as we also highlighted in today's presentation, and there's a long list of measures being implemented by Aker BP as we speak, while we're executing the projects to mitigate that exact observation. Do you want to talk about dividends?

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

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

Let's move on, Kjetil.

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

Still can't hear Tianhong.

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

Can you hear me?

Yes, we can.

Just a couple, please. Just firstly on Wisting. I guess you sort of flagged it as an important project in the longer-term production profile. Just what's the situation? Any progress update there? And I guess, whether you've been able to utilize any of the AI that you've talked about in terms of accelerating that project or improving the economics. And then just on the exploration campaign for the year, 12 wells, they all look to be in the North Sea, nothing in the Norwegian Sea or the Barents. I'm just wondering if that's a sign of things to come in the exploration strategy or just the way it's fallen this year?

Thank you, James. When it comes to Wisting, obviously, we are not the operator. So the way I see this is that the sea studies is starting. We will likely choose an engineering provider sometime mid-2026, and then a DG2 towards the back end of '26, and a DG3 towards the back end of '27. And then hopefully, an efficient execution model. And then I'll ask you to question the operator, whether they're implementing any of their artificial intelligence. When it comes to exploration, this is a bit simpler actually. In 2026, we are spending most of our available rig days drilling the production wells that goes across the semi-subs and also the jack-ups. That means that we, from an operated perspective, have concentrated on the Utsira High area. So this is basically just an allocation of rig capacity in 2026. And then you might have noticed that we've actually contracted a new rig from 2027, the Noble GreatWhite to add in capacity to cater for the higher-than-expected wells to be drilled need. As you also saw in the presentation, we now have several IOR targets and new wells rolling into the portfolio as a result of the ongoing drilling campaign. So the 2026 campaign is simply an allocating of rig resources. All right. Let's move on, or move back, as the case may be.

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

Can you hear me?

Absolutely.

Perfect. I have 2 questions, please. I thought it was really interesting to hear the digitalization and AI deployment at Aker BP as well as your alliance model, which is very differentiating. I wonder if you are able to quantify the impact of those on your financial performance such as production cost per barrel? I don't know, a lot of savings, perhaps in the long term, if you can quantify that, that will be good, or just give us a bit more color on that. Then my second question is on your 2026 production guidance. I want to ask, let's say, if we exclude the acceleration of 2027 production that was brought forward to 2026, for example, the Skarv area, the Utsira High area, what would be the underlying production range?

Yes, you might have a think about the last question while I answer the first. So first of all, I think it's fundamentally important to understand this discussion around digitalization. And the way I usually describe it is that this is almost a continuous process. So you first optimize, call it, the analog work process. Then you digitalize it by implementation of tools and transforms and human machine interfaces and the whole stuff that we're used to in the retail space. And then now we are taking the next step, and we're implementing artificial intelligence. But that is a completely different way of thinking about organization, processes, competence, needs, et cetera, et cetera. And as an example, what usually was a planning process for a maintenance operation or maintenance planning offshore would usually take about a week from start to finish. Now with Agentic AI and Agentic-powered tooling, we can actually do that in a matter of minutes, not in a matter of days. And we see the same thing in root cause analysis, what used to take weeks are now taking hours. So you're actually observing a collapse in work processes that we haven't really seen before. And we're able to do this because over time, we have invested in what was ultimately an AI-ready architecture where you can deploy these systems and agents on top. And then this discussion around saving, I'm also having a little bit of a problem conceptually with that idea, because that takes as a starting point that you have some sort of fixed underlying performance and then you're measuring your performance against that underlying performance, which might be fine if you were improving analog processes or implementing digital tools on analog work processes. But what you're actually doing here is that you're fundamentally transforming the way an organization works. So there is really nothing to compare it against. What you should be looking for is cutting-edge performance in terms of time to first oil. You should look at our ability to discover oil. You should look at our underlying performance in terms of uptime, plant efficiency, maintenance efficiency, et cetera, et cetera. It will take a bit of time before that works itself into the financials. But I think that is the ultimate proof point. I really struggle with this idea and companies coming out and saying they've saved X, Y and Z by implementing this and that. I really don't understand how that is a measurable quantity. You want to talk a little bit about production guidance?

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

And very important for the Skarv asset.

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

Let's move on, Kjetil.

Yes. Then next caller is Victoria McCulloch from RBC.

Can you hear me okay?

Yes, we can.

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

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

Yes. '25, you mean?

'25, I mean.

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

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

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

Two questions, if I may. Firstly, CapEx, not so much the impact on '25, '26, but I'm interested, longer term, do you think you've moved up from that sort of $15 a barrel of incremental CapEx spend to hold that production at above 500,000 a day. And I'm interested how much do you think, if so, that has gone up? How much that has increased? Secondly, a question on reserves. Total 2P plus 2C end of '25 was up only 20 million barrels versus end of '24, and that's despite the excellent exploration success you've had this year. I wondered then if those barrels from this year's exploration success are actually going to come into the reserves numbers next year instead, because I was surprised there was such a small increase in those numbers. That will do for now.

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

I can cover that.

Yes.

So what we have said in the past, Chris, is that we expect a range between $15 to $25 per barrel going forward. And then we have said that when you invest in new facilities to create, call it, facilities to also cater for area developments, new tiebacks and so on, you could put in place infrastructure, which drives up the, call it, starting point on the cost per barrel in the higher end of the range, while when you're drilling infill wells or doing subsea tiebacks, that number should typically be lower. And then you can see that, for example, from the wells that we now added in the PWP-Fenris project, the 5 wells there. And when you look at the number of resources we're adding, the cost per barrel goes down quite significantly, right, because you've already pre-invested in the facilities. So there will be a range. And there's nothing that's happened since we discussed this last time, which indicates that, that number is increasing significantly.

Quite the opposite.

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

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

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

Okay. By Proxy, that's great.

From Tianhong Bi of Citi. Good to see some update on the Sverdrup redetermination process. We've seen a very wide range of possible outcomes on the NCS recently. With the results just a few months away, are you able to shed any light on what we should expect at this stage of the process? And please just remind us, if the outcome is favorable for you, would that trigger any cash reimbursements this year? Or is everything settled through future production? And does the upper end of your CapEx guidance include any contingency for a potential reallocation? It is interesting to see you have been awarded for several tight gas reservoirs in the latest APA round. Those historically have been viewed as uncommercial. Given your portfolio is quite oil-weighted and you've typically prioritized higher return, low breakeven projects, this looks like an unusual move. What's driving your interest in tight gas now?

Excellent questions, and well presented. Thank you, Tianhong. On Sverdrup, I think you should -- I think I'll refrain from commenting both on process. But I can say that any changes to tract participation in Johan Sverdrup is not accounted for in our 2026 forecast, whether that is on the production or on the CapEx side. And then if there is attract participation change, that means that if it's positive to us, that means that the production will go up slightly. We haven't accounted for that, but CapEx will also go up slightly. And there are a 2-year kind of restatement process for '26 and '27. So neither is accounted for in our guidance for 2026. And then on process, I think I'll leave that to the operator to comment on. On tight gas/tight oil, I think it's important to note that we've actually been a very active operator of tight oil for a long time in Aker BP. Valhall field is essentially a tight oil play, and we have been probably the most active, call it, deployer of fracking technology and other stimulation technologies against a tight oil play. So we have, for quite some time, spent a bit of time and resources understanding the tight oil. And then your question, why, and I understand that you might believe this is an important move. Well, I'll go back to where Teodor started this morning, pointing out the challenges on the Norwegian Continental Shelf keeping the reserve number up. If you look at the total amount of discovered but undeveloped resources, tight oil, tight gas constitute by far the largest portion. So for us, focusing on the Norwegian Continental Shelf and building on years of experience with tight oil and tight gas and the fact that we are now essentially outdrilling the other operators on the Norwegian Continental Shelf, and drilling is such an important part of the cost in tight oil and tight gas, it was actually a natural move for us to now go after these resources. So that means that we have picked up, as you correctly point out, quite a number of licenses, and we're progressing technology projects and development projects in parallel. We do believe that this will be highly value-accretive barrels on the Norwegian Continental Shelf with a significant volume potential.

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

Can you hear me?

Yes, we can.

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

Thanks, Mark. I certainly buy into your statement that this is actually nothing new. What we're seeing now is pretty spot on what we have in our models and our projections going forward and what we have had going into 2026. The variables here are, as almost any other field, I would say, essentially trying to stop the decline by drilling new wells or implementing well changes for us. There are new wells being drilled at the DP. There's a retrofit multilateral campaign, which we've now been in the middle of, and one well has started up and another well is coming. And then you have the Johan Sverdrup Phase 3 project coming on stream in 2027. So that's basically what we would, in any other field, call an IOR campaign and should be considered the same here, and there will be more. And then it's all about how we actually run production. It's about the balance of mass outtake, volume injection through the water injection system, and then understanding how the coning and the coning behavior of these wells behave. And again, and I've said this several times in this presentation, here I say Statoil is doing an excellent job and have been doing an excellent job mitigating and fighting the decline. I see no new information. And I still believe that Johan Sverdrup is a fantastic field that will continue to outperform. I think we lost Mark. So let's move on.

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

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

Absolutely.

Fantastic. That's great. Two questions on exploration. First, I noticed that you're drilling an exploration well in the Johan Sverdrup area, the Tonjer now in Q1. I just wonder -- a bit curious actually, it looks like it's relatively small potential for that well. But I just wonder, is this a small pocket you're drilling? Or is it testing for a potential new play opener, so to speak, for the area? And also, if it turns out to be a discovery, is this something that could be tied in and start production fairly soon? So that's the first question on the Tonjer exploration well. And secondly, more in general, you're using a lot of AI, as you say, on exploration. I just wonder the implications -- are the implications that you will need more seismic data, but we'll be able to drill fewer exploration wells? And then the second part of that question is, do you expect to increase exploration success rates going forward? Maybe also comment a little bit on potential difference in commercial success versus technical success. As you know, in Norway, there's been a lot of technical success, there's fewer commercial successes. So if you could elaborate on a little bit of that as well, please.

Sure. Absolutely. Thank you, John. Tonjer, Tonjer is essentially the northernmost extension of the Johan Sverdrup field with a possibility of a difference in oil quality, oil-water contact, et cetera, et cetera. So that's why we're drilling an exploration well. No, it's not -- I would really wish it to be a play opener, but I don't consider it a play opener. I consider this more almost like an appraisal well to understand whether there is a basis for a subsea tieback from the Tonjer area back to the Johan Sverdrup field. And then I do sincerely hope and would urge the operator, if we do make a discovery, to expedite the tieback of Tonjer to the host. And then on AI, I don't think it will change the way we consume seismic in terms of volume. I think it's -- a better way of looking at it is, it's almost like a digital laboratory, right, where you can test concepts, you can dig into data, you can actually play with concept and then hold that up against the database that you have in a consistent manner. You could always do stuff like automatic seismic interpretation and data analysis. And, of course, machine learning algorithms driven by AI agents is kind of revolutionizing the pace we are retransforming this data to test different hypothesis. But I don't really see that there's a fundamental change in our consumption of data, maybe with one exception, and that's the move from towed streamer seismic to ocean bottom nodal seismic, simply because these algorithms are now using not only the pressure wave, but also the shear wave to optimize what they basically call the way of differentiating between rock and the fluids in the rock. And yes, of course, it is for us about increasing the chance of success. It's about avoiding drilling wells where we can see that there has been a bias by the people involved. I mean, we all get to fall in love with our concepts, and I do that all the time. Fortunately, I have David, which is helping me break out of those love relationships for most of the time. But it is about actually understanding what are the real data and what is the bias data. It is about testing more plays. So it's also about acceleration and processing of more data on the Norwegian Continental Shelf. And yes, we are, in fact, kind of digitally drilling exploration wells into these models and testing the data before we actually do drill. So over time, I expect also a higher chance of success. And where the wells we actually do drill are much better based on the data that exists. And then there are areas on the Norwegian Continental Shelf, you could call it the high potential areas, where there is actually little data. And it is a fact that AI actually only works if you have sufficient amount of data to educate the algorithm. So there will be a kind of a balance between humans and the AI interacting with the data. So it's a little bit of a mixed picture, but it is certainly a lot of promise in the way we are now deploying artificial intelligence in the subsurface disciplines.

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

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

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

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

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

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

And then Kjetil, we'll close for today.

Yes.

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