Today is the Aker BP CMU. What a year 2020 has been. It has turned out differently from what everybody expected. The COVID pandemic, the oil price crash in March, and then the general uncertainty we have all felt. 2020 has really been challenging. When you run oil and gas facilities, you always plan for different scenarios. You run analysis, you evaluate risk and consequence, you train for strategic response, you train for emergency response, and then for good measure, you do some more analysis and train some more. Still, to deliver on these plans in real time, in real life, is something completely different, and I truly believe most of us, we don't rise to the occasion. We deliver according to the level of our training, and that's why I'm so incredibly proud of the Aker BP team. They have really risen to the occasion in 2020 and demonstrated what Aker BP is all about how to solve challenges, how to thrive under very uncertain terms, how to dare to make the right decisions at the right point in time. Back in March, our main priority was to protect our people and our operations from the virus. We implemented a strict regime of travel control, quarantine hotels, and testing facilities. This has resulted in zero incidents of COVID-19 on any of our installations, and the regime is still in force. Another top priority was to protect our financial strength. We delayed all new investment decisions, postponed exploration wells, and we cut the dividend by two-thirds. Then in June, the Norwegian Parliament voted to make temporary changes to the Norwegian tax regime, both to stimulate activity and employment. Those changes made it possible for Aker BP to resume our business activity. Of course, just as we had scaled down this activity, we now needed to scale it back up. Hey, a cup of coffee? Yeah, that would be fantastic. Looking back one year, I definitely think that in the beginning of 2021, we're better off than we were in the beginning of 2020. Despite all challenges, we had delivered on our production guidance with strong HSE performance, without COVID incidences, and the cost ended up well below our initial plan. Our financial position is strong, we have a large hopper of profitable early-phase project that allows us a unique opportunity for value creation. When it comes to these projects, we have demonstrated that alliance model is the superior way of delivering these projects on time and on cost, as is really well demonstrated by the Ærfugl projects. Aker BP has formed strategic partnerships with our most important suppliers, working together as one team in the Aker BP alliance model. Common goals and shared incentives have led to significant improvements, the latest example being the Ærfugl project, executed through the alliance model. The Ærfugl field is located west of Skarv. The reservoir extends over 60 km and holds a total of around 300 million barrels of producible oil equivalents. This innovative project represents important technology developments that will enable future profitable investments on the Norwegian Continental Shelf. New and innovative technology has been implemented to overcome the challenge of the long distances with electrically trace-heated pipe-in-pipe technology, qualified and utilized for the pipelines. The Ærfugl project has also introduced other innovative solutions, such as vertical subsea tree technology, providing easy access to the wells and hence reducing the complexity and cost of future well interventions. The Subsea Alliance, the Semi Alliance, and the Modification Alliance have all been vital to this project. Together, we have demonstrated substantial improvements and increased the value creation from the Ærfugl project. The team has executed this complex project safely and efficiently, on time and cost. The alliance celebrated the successful production start from phase I in November 2020 and is now working to bring the remaining two wells from phase II on stream by the fourth quarter of 2021. Hi, Karl. Good morning. Hey, did you guys solve the problems on the completion on the Bass well? Yeah, we did. Took us 40 hours, but the team is really motivated to get back on track. 40 hours lost. 40 hours lost, but it'll be regained. When is the capital markets coming up? It's actually today. Today? Yeah. What the hell is your pitch? First of all, we are going to remain a pure-play oil and gas company, but we are going to- On NCS on the NCS, but with a very strong hydrocarbon performance. Yes. Second, we are going to operate our assets at low cost and high efficiency, and we are going to leverage the digital agenda we just talked about. Thirdly, in this industry, we need excellent execution skills, and I think we have proven that the alliance model is the superior model to deliver these projects. I think it's important to stress that point, that the alliance model has been working for us, and it's been working not only for us but our suppliers. In the next six, seven years, we're going to go from 200,000 barrels to 350,000, 400,000 barrels, and how do we do that without increasing cost? That's exactly the point. We have 11 of these early-phase projects. They're all in the alliance models, and they're all on track. Are you able to explain what we are doing on the digital side? I think it'll be very clear for the people viewing the NOAKA project that this is going to be a digitally native project for the first time on the Norwegian continental shelf. I've been looking forward to this for five years, so please get the point across, Karl, because that is the thing to get across to the investors in this. I really like that. Then I think also the final point, we have a very, very strong balance sheet, a good cash flow, and we are. Did I hear dividend? You heard dividend. Thank you. We are going to continue to pay an attractive dividend also going forward. Okay, Karl. Beauty for beauty. Thank you. Give them hell. Have a good one. Take care. Aker BP is a pure-play oil and gas company, and we plan to keep it that way for several reasons. One reason is the market outlook. Yes, there is an energy transition underway. However, oil and gas will remain essential for the world to maintain an affordable, secure, and sustainable energy system. When we break down the energy mix, we see that 55% of energy demand is covered by oil and gas. Coal brings the share of fossil fuel up to as much as 80%. In a sustainable development scenario, the International Energy Agency outlines a major transformation of the global energy system in line with the goals from the Paris Agreement. In 2040, it is estimated that oil and gas will be more than 45% of the global energy mix. Oil and gas will continue to play a vital role as an energy source for many decades. In addition, oil and gas demand is also growing outside the energy sector, for instance, in petrochemicals. That said, it is not enough to invest in oil and gas projects the same way that this industry did before. The industry needs to change, and Aker BP has set out on that journey. The oil and gas companies of the future need to be more adaptive, more efficient, and more sustainable, and this is exactly where Aker BP has its most important role to play. The climate challenge can only be solved if oil and gas companies are mobilizing the full scale of their technical and commercial capabilities. In this context, let me be clear on Aker BP's contribution as a pure-play oil and gas company. First, we will maximize value creation from our assets and operations. This means that we also maximize the profits we can distribute back to our shareholders and the taxes we pay. These profits or taxes can then be redeployed elsewhere, wherever the economic and environmental returns are more attractive. Our competitive edge is within oil and gas. When it comes to investments in renewable energy, other companies are better suited for the job. That is why, in order to maximize value, we will continue to focus on what we're good at. Second, we are committed to minimizing emissions from our operations and assets. This is, of course, important in the environmental perspective, but it's also starting to have a direct financial impact as cost of emitting CO2 is on the increase. It is therefore encouraging to see the amount of reductions that can be achieved through the smart use of digital tools with limited capital spend. We will continue to push hard to improve energy efficiency and reduce waste in our operations, and thereby further improve our carbon footprint. All new field developments will be powered by renewable energy and hence will be at virtually zero emissions. In our business plan, we expect to reduce our emissions intensity by 50% during the 2030s, and by 2050, it will be close to zero. Third, the energy transition is not just about how we produce energy, but also how we generate new industries and business opportunities. Aker BP is determined to play a central role in this part of the puzzle as well. At Aker BP, we have created a culture and an attitude for data sharing and collaboration across our operations. One excellent example is Cognite, a company we co-founded to help us liberate and contextualize data, which is quite essential for a digitalization strategy. Cognite has grown to become one of the most interesting industrial software companies in the world, serving customers across a wide range of industries, and is a shining example of what we're talking about here. Another example is our collaboration with Aker Offshore Wind, where we will contribute with industry and technology competence and be a potential customer of electricity from offshore wind, along with other operators. The aim is to drive down CO2 emissions on the Norwegian Continental Shelf and help create a new green industry with scale to supply electricity to offshore platforms. To sum it up, a transitioning world will need the most carbon and cost-efficient barrels of oil to be produced. This happens to be at the core of Aker BP's strategy, as it's been for years already. Let's take a closer look at our operations, where we stand today, and what we want to achieve. Aker BP operates five hubs for oil and gas production in the Norwegian continental shelf, with a gross daily production of nearly 300,000 barrels per day. Operational excellence is therefore at the top of our agenda. Since 2016, we have nearly tripled our production. Going forward, we also have bold growth ambitions. Succeeding with our growth plan starts with operating our current assets safely, efficiently, and with low cost. In 2020, production cost ended at $8.30 per barrel. This was a significant step down from the year before, helped by top quartile production efficiency of 92%, as well as contribution from new low-cost production from Johan Sverdrup. We have an ambition to improve this further, and we're aiming for $7 per barrel. This requires a relentless focus on efficiency improvements, as well as bringing new wells on stream to maximize the capacity utilization of our assets. Our CO2 emission intensity was well below five kilograms per barrel. This is about one-third of the world average and puts us firmly in the low end of the scale. Our goal is to stay below five kilograms and to improve even further. In addition, our methane emissions remain low, and the goal for 2021 is not to exceed a methane intensity of 0.1%. In a difficult year with COVID-19 restrictions, we have delivered a strong safety record. Maintaining and further improving the HSE performance requires relentless efforts and continuous attention. Aker BP continues to strengthen our safety culture based on a strong foundation of systematic learning from incidents and structured risk management. Our safety standards are high, and our goal is obviously zero incidents. No one should be injured or harmed from working in or for Aker BP. Although we are happy with the 2020 results, we're always looking for further improvements. Every day, our focus is to run our assets safely and efficiently. As I've said, the future require oil companies that can operate more efficiently, be more sustainable, and adaptive. A key word in this context is digitalization. This is one of the main pillars of the Aker BP improvement program, and it is an area where we've made significant progress over the last years. We started with the operational side of the business, and together with John Markus Lervik and Aker, we established Cognite, and in turn, we developed the CDF platform where we are now aggregating all our operational data in one single platform available 24/7 with very low latency. CDF gives Aker BP a competitive advantage and is probably the only technology platform that allows contextualization of all data consumed by Aker BP. The next step was to start using the data to improve our business processes and decision-making because only then can digitalization create value. However, digitalization requires competence and new ways of working. To tackle this problem, we've set up our own digital organization, EurekaX, to manage all digital projects in Aker BP. We have sought inspiration in work processes found in technology companies rather than the traditional processes of the oil industry. The EurekaX team is now continuously working together with our operational teams to transform key business processes and drive improvements throughout the company. Another important focus area is the project side. Here, we believe digitalization can contribute to radical improvements when it comes to both time, cost, and quality, hence lead to increased returns on our investments. We have been working on this for quite some time, mainly in cooperation with Aker Solutions. This activity has now been moved into Aize, a separate startup where we own 10%. We will work with Aize to further develop the digital project execution model, which we will initially be using for our own projects. We aim to commercialize the product offering just as we've done with Cognite. The next big thing for us is subsurface. We already have enormous amounts of seismic surveys, well logs, and production data, but too often the data are locked in. Once we liberate this data and make them available in one common platform, I believe we'll see a revolution of data-driven automation, innovation, and insight, which will again contribute to more value creation. I am very pleased with our performance and our achievements so far. We cannot rest on our laurels, and I can promise you Aker BP will continue to improve the way we do business. I'm now on the platform deck of Valhall, one of five production hubs operated by Aker BP. Valhall started production in 1982, and in 2013, it was electrified with power from shore. So far, more than one billion barrels of oil has been produced from the Valhall area. Still, Valhall is a field of the future, and our vision is to produce another billion barrels from this area. Our operated hubs are different in many ways, but the overall goals are the same. Every day, our job is to operate the fields with zero accidents, with high production efficiency, and with low emissions and low cost. Our vision is to be the leading offshore E&P company, and we are continuously looking for ways to improve. As part of our improvement program, we have established strong alliances with our key suppliers, and we have expanded our digital capabilities. We have optimized our work processes, and we have been testing out new business models. The next leg of this improvement journey is to combine all our experience and learnings from these initiatives into a new operating model, which will be standard for all assets operated by Aker BP. This operating model covers many areas such as HSSE, maintenance, digital operations, procurement, and logistics. We believe standardization in these areas will bring significant benefits. Firstly, it will drive cost efficiency and safety by making sure we do things according to best practice. Secondly, it will create synergies through better collaboration across the organization. Thirdly, it adds scale and speed to our continuous improvement, for example, by enabling further digitalization of manual processes. It's always possible to improve, therefore, the new operating model is not a finished product but a start of a journey. To give you a little glimpse into what this means in practice, let's look at some real examples. Offshore oil platforms are huge and complex structures as you can see, we frequently need assistance from external experts to perform inspections, to supervise specialized work, or to operate, maintain, or modify equipment and systems. This involves a lot of offshore travel, which in addition to the safety aspects, is both costly and time consuming. It has therefore been a long-term goal to move this onshore. During the COVID pandemic, this has become a necessity. In the new operating model, we have established the concept of remote first. Activities that can safely be performed onshore at the right quality should always be done onshore. This applies both to our own employees and to our suppliers. We already have the building blocks in place. We have built a digital infrastructure with real-time data access. Our offshore operators are equipped with connected handheld devices for easy access to data and communication. We have set up onshore collaboration centers to remotely support our offshore activities. We have suppliers who are highly motivated to take part in this transformation. One example is the certification company DNV GL. Two months ago, they successfully performed the first remote inspection of a crane here at Valhall using a live video link. Similarly, we are working closely with several other suppliers to develop remote capabilities, including ABB, Kongsberg, Siemens, Halliburton, and Aker Solutions. Another very important focus area for our new operating model is maintenance. Maintenance represents a significant part of our production cost, and we believe there is a huge potential for savings by optimizing these activities. In the future, most of our maintenance activities will be bundled together in campaigns focusing on one installation at a time. Each campaign will be planned in detail to ensure high precision and quality. We believe this will be more efficient and lead to more uptime and higher production efficiency. To plan and execute this work, we are establishing specialized maintenance teams. This way, we can build more competence, and we can share this expertise across all our assets. We are also working actively to minimize our CO2 emissions. The main driver of CO2 emissions in Aker BP is energy consumption. To reduce emissions, we therefore need to either switch to renewable energy sources or increase the energy efficiency. Both Valhall, where we are today, and the Johan Sverdrup field are already powered with clean energy from the Norwegian mainland. Next year, Ivar Aasen will also be connected to the grid. The CO2 emissions from these fields are therefore already among the lowest in the industry. For our other fields, electrification is currently not commercially viable, so here the main focus is on energy optimization. However, we are performing studies on alternative power solutions that might become feasible in the future. We are continuously monitoring the energy consumption at our installations, and we work systematically to identify improvement potential at all our assets. These opportunities are then ranked according to environmental, technical, and economic effects, and the best projects are selected for implementation. Last year, we completed six projects under this program, which in total contributed to an annual reduction of nearly 15,000 tons of CO2. In addition to the environmental benefits, these projects also contributed to either lower cost, higher production, or both. This year, we have so far planned two new initiatives, and I expect more to come. One of these is here at Valhall, where we will replace a diesel generator and electrify the coil tubing pump. Remote operations, maintenance, and energy efficiency are only three examples of areas where we are targeting significant improvements in our operations. The purpose of it all is to bring us closer to our vision to be the leading offshore E&P company. In operational terms, this means high safety standards with zero accidents, high production efficiency, and low cost and low emissions. Efficient operation is obviously a key value driver for Aker BP. Another very important area where we also want to be leading is project execution. This is where the major part of our capital is invested, and flawless execution is essential to ensure that we generate the required returns on capital. When we established the Aker BP Improvement Program five years ago, one of our observations was that traditional project execution model of our industry was inefficient. The project organization was fragmented, there were too many interfaces between customer and supplier, and incentives were not aligned. Too often, this led to poor flow of information, bad decision, slow progress, cost overruns, and low quality. Our answer to these challenges was to establish the alliance model. This model has been used with success for decades in other industries, so we did not invent it, but we adapted it to suit our business. One purpose of the Aker BP alliance model is to remove the barriers between supplier and customer, and we do this by merging our own employees with those from the suppliers into one single team with common goals and shared incentives. Another purpose is to maximize the learning effect. A lot of the things we do are repetitive tasks, and by keeping the alliance team stable from one project to the next, we create an arena for continuous learning and improvement. This leads to improved performance over time, both in terms of time, cost, and quality. A third important aspect of the alliance model is that it contributes to long and strong relationship with our key suppliers, built on commitment, trust, and mutual benefit. This can be of high value, especially when things don't go as they plan, as they sometimes do. More than once, our alliance partners have helped us solve problems with the speed and quality that would not otherwise have been possible. We have already made huge progress with our alliance model. Our subsea tieback project are executed much faster than before, our drilling operations are more efficient than ever, and we are building platforms faster and cheaper. The Hod development is a very good example. This project is as close as it gets to a full copy of the Valhall Flank West project, with the same team doing the same job based on the same blueprints. Even if we do need to make some post-installation modifications, this has proven far more efficient than starting from scratch. The decision to develop Hod was made immediately after the Norwegian Parliament, with broad political support, made the temporary changes to the petroleum tax system in June. These tax changes came as a response to a sharp reduction in investment activity in Norway following the collapse in oil prices in March. The temporary tax system involves a boost of liquidity to stimulate oil companies to resume investment activity. In line with the intention, it is contributing to maintaining competence and capacity in the Norwegian oil service industry. This is good for the Norwegian society at large, both in terms of job creation and increased tax revenue to the Norwegian state. The temporary system applies to all investments made in 2020 and 2021, and to all investments until production start for new project where a field development plan is submitted to the authorities by the end of 2022. The tax changes are only really helpful if you have the project to invest in, and Aker BP is very well positioned in this regard. Our contingent resources are estimated to around 900 million barrels. These are oil and gas discoveries where we have not yet made a development decision. These resources come in addition to the 842 million barrels of 2P reserves in our producing fields. This resource base provides a strong foundation for value creation, and we're continuously working to mature these resources and convert them to profitable investments. When the COVID and oil price crash happened last year, we decided to put all new investment decisions on hold to preserve our financial flexibility in a highly uncertain situation. A few months later, the tax changes turned this around, and we have resumed the work. This is a list of projects we have given priority. We aim to sanction this project by the end of 2022, hence, within the temporary tax system. In total, these projects represent more than 500 million barrels, with an average break-even oil price of around $27 per barrel. This is approximately $8 lower than it would have been in the ordinary tax system. The capital needed to fund these projects are reduced to less than half. I sometimes get the question: how can we deliver all these projects? Do we have the capacity to do it? The fact is that most of these projects are just a continuation of the ongoing project activity already in Aker BP. For instance, in the Alvheim area, we have project named Frosk, Trell and Trine, and Kobra East & Gekko. All of these will be tied back to the Alvheim FPSO in sequence. In this area, we have been routinely adding new tiebacks since startup in 2008. For the last three or four years, these projects have been executed through our subsea alliance with Aker Solutions and Subsea 7. The performance has been excellent, and I'm confident that our alliance team will continue to deliver. The Skarv satellites consist of discoveries like Shrek, Ørn, and Alve Nord. These will also be developed as subsea tiebacks. We have the same alliance partners here as in the Alvheim area, and this team has just delivered the Ærfugl Phase I and are now continuing with Ærfugl Phase II and the Gråsel development. The satellite project will follow suit. At Valhall, we are planning to add a new platform at the field center, the so-called NCP. Here we are currently building the Hod platform, which is a copy of the Valhall Flank West. The NCP is next in line, and will be built on the team and experience from its predecessors. NOAKA is a tieback project to Ivar Aasen, with many similarities to those in the Alvheim area. Can we deliver? We have the resources in the ground, we have the financial flexibility, and a supportive tax system, and we have a team that is highly competent, experienced, and motivated. Not least, we have our great alliance partners, and therefore, I am confident that we got what it takes. NOAKA is by far the largest project on the list and deserves a much more thorough presentation. I have the privilege of leading Aker BP's work on the NOAKA project. As you can see, the NOAKA team is working full speed ahead with the project. NOAKA has been in the making for many years and has faced its fair share of obstacles on the way. In June 2020, with good help from temporary tax changes, we reached an agreement with our partners on a commercial framework for a coordinated development of the area. The clear target is to have the development plan ready in 2022 within the time window of the temporary tax system. The starting point for any oil and gas project is the resources in the ground. Let us take a look at the resources we have to work with in this area. In total, we have eight discoveries within a radius of 30 kilometers from the center of the area, which is located between Alvheim and Oseberg in the North Sea. Total resources are estimated to more than 500 million barrels of oil equivalents. Of this, around 60% is oil and condensate, while the rest is natural gas. In addition to these proven resources, we also see significant upside potential in the area. One example is Liatårnet, a discovery from 2019 where we will drill an appraisal well this year. Another example is East Frigg, an old gas field which was shut down in the '90s, where there could be significant oil volumes remaining in the ground. There is also additional exploration potential in the area. Altogether, this makes NOAKA one of the largest and most exciting remaining field developments on the Norwegian Continental Shelf, and it is, of course, a huge value creation opportunity for Aker BP. Currently, we are preparing for the concept selection. It will be a complex development with many pieces of infrastructure linked together. In the southern part, there will be a processing hub located above the Frigg Gamma Delta reservoir operated by Aker BP. At Krafla to the north, there will be an unmanned processing platform operated by Equinor. In addition, there will be probably three unmanned wellhead platforms and four subsea tiebacks to make sure we can reach all the corners of the resource space. Both the southern and the northern processing hubs will be supplied with power from shore, and hence have close to zero CO2 emissions. There is still a lot of choices to be made. The drilling strategy must be optimized to make sure we maximize recovery. The top side facilities must be able to handle expected volumes and hydrocarbon types, and we must make sure that we have an adequate power supply. Together with industry partners, we are also looking at the opportunity of combining power from shore with offshore wind. Wind turbines are not a part of the NOAKA project as such, but we want to contribute with knowhow and be a demanding customer. It would be fantastic if we could help giving birth to a viable offshore wind industry in Norway. This would increase our access to clean energy, and it would further improve the environmental footprint of the Norwegian oil and gas industry. The NOAKA project will be the largest project ever for Aker BP, but we are not starting from scratch. We will run the project using the alliance model, working together with our suppliers as one team with common goals and shared incentives. Together with our alliance partners, we have established a highly competent and experienced team. Collectively, this team has delivered many successful projects in the past, which are highly relevant for NOAKA. For instance, the subsea technology developed for the Ærfugl project and the wellhead platforms for the Valhall Flank West and the Hod developments. We also have highly competent partners in Equinor and Lotos, I'm very satisfied with the good collaboration that has been established in the entire partnership. The NOAKA project will also be setting new digital standards. The project will be the first ever to use a fully digitalized execution model. I'm deeply impressed with what I have seen so far. Together with Aker Solutions, Cognite, and Aize, we have come a long way in developing this model. I am convinced this will contribute to significant improvements when it comes to efficiency, cost, and quality. NOAKA will also be developed with state-of-the-art solutions for automation, remote operations, and smart maintenance to ensure maximum efficiency and minimum cost in the operations phase. As you see here today, we are using our collaborative well planning setup to optimize our drilling strategy, because one of the most important factors in achieving our break-even hurdle of $30 per barrel is successful well planning. Right now, we are in the middle of a collaborative well planning session for the well placements in the Rind area. Part of the team sit together here in the onshore collaboration center in Stavanger. Reservoir and well expertise from other locations connect digitally. They work together in an efficient way to get a common understanding of value and risk for specific wells in this area. Collaborative Well Planning, or CWP as we call it, includes software, data flow, and a team of experts from different parts of the organization working together in agile sprints. It allows testing of many concepts in a very short period of time. CWP is a way of working developed through our digitalization program, EurekaX. Aker BP is planning 25 wells in the NOAKA area. Through CWP, we can test far more ideas and scenarios than before in the concept selection phase of a project. This also means lower risk and increased recovery. As you can see, we are working at full speed to clear the path for a profitable NOAKA development. The big milestones coming up are the concept select in third quarter this year, followed by final investment decision before the end of 2022. Production start will most likely be in 2027. We will then have established a new production hub for the company, one that will create value for decades. My hope is that we also leave another legacy, a new standard for project execution. I'm really encouraged by the progress on NOAKA, and this will be a groundbreaking project in many ways. It will generate substantial value for Aker BP, and with a digital execution model, it will also set the new industry standard for efficient project execution. Another groundbreaking project is, of course, Johan Sverdrup. Since production started in 2019 on time and well below budget, good news just keeps on coming. Last quarter, the production capacity was expanded to 500,000 barrels per day. The operator, Equinor, is now working on increasing the water injection capacity at the field. This will increase the capacity to around 535,000 barrels per day this summer. This is more than 20% higher than the design capacity at startup. The second phase of the Johan Sverdrup development is well on track for startup in 2022. This will add a third processing train to the field and increase production capacity to 720,000 barrels per day. Sverdrup is impressive, not only because of its sheer size. In economic terms, it's also extremely robust, with lifting costs below $2 a barrel and a break-even oil price below $20. With power from shore, it may be the lowest emission intensity in the entire industry. When we add it all together, our five operated hubs, Johan Sverdrup, NOAKA, and the other project I showed you, plus several smaller projects and infill wells, we are aiming to produce more than 350,000 barrels per day in 2028. This represent an organic growth of more than 70% compared to the 2020 level. With low cost and breakevens below $30 for these new developments, we are confident that this growth will create substantial value for Aker BP and its stakeholders. Clearly, these projects are on top of our agenda, but we're also looking further ahead. We will continue to mature the rest of our resource base to prepare for the future developments. Some of these are included in the 900 million barrels of 2C resources, for instance, King Lear. We also have several discoveries which are not yet included in the 2C numbers, like Liatårnet in the NOAKA area. We will continue to add resources through exploration. We have two main goals for our exploration strategy. The first goal is to find more oil and gas near existing infrastructure. Such discoveries typically have short lead times and attractive economics and contribute to high capacity utilization and low unit cost at our hubs. In our 2021 exploration and appraisal program, we have six wells in this category, mainly concentrated in the North Sea. The second goal is to find resources that are big enough for new standalone field developments. In recent years, the Barents Sea has been the main basin for this activity. The results have been disappointing. We have two more Barents wells on the program for 2021. When completed, this will mark the end of our Barents campaign. We will take a step back to evaluate our future strategy in this area. Whether or not we will drill more wells in the Barents Sea post-2021, time will tell. Another way to grow the company is through M&A. Historically, we've been very active on this front, and we are continuously evaluating the opportunities that comes our way, but we will remain true to our principles. Our focus is on quality assets with upside potential, and we prefer to have the operator role. Every deal we do has to be financially accretive and create shareholder value. At the end of the day, the purpose of everything we do in Aker BP is to maximize value creation. To achieve this, we must allocate capital efficiently, balancing short and long-term objectives in a volatile world. When the oil price collapsed in March, it was a call for action. We had to weather the storm and make sure we chose the right path forward. We immediately mobilized a team headed by our CFO, David Tønne, to work with the management board to revisit our financial plans. After 14 hectic days, we had developed a new bottom-up plan, got the board's approval, and communicated it to the market. Now I think it's time for you, David, to give us your perspective on this volatile year and the capital allocation priorities going forward. Thank you, Karl. You know that I'm more than happy to do so. 2020 was a very challenging year for all of us. For Aker BP, 2020 was also an opportunity to demonstrate how the company performs in extraordinary circumstances. Not only how our organization execute under pressure, but also the flexibility of our investment portfolio, and of course, the resilience of our balance sheet. Through 2020, we definitely had to make some clear priorities, but I believe these priorities also provide clarity on how Aker BP will act going forward. Our number one priority is to safeguard the health and safety of the team. In 2020, we chose to invest significant amount of time and money to avoid spreading COVID-19 offshore, protecting both people and production. In 2020, we took precautionary steps by postponing both investments and dividends to protect our financial flexibility and our ability to create value. Looking forward, I think Aker BP has never been better positioned for value creation. Our operational performance has never been stronger, the balance sheet has never been more robust, and our investment opportunities have never been more attractive to pursue. Today, I will spend most of the time on our updated capital allocation framework, including our latest investment plan and our new policy for shareholder distributions. The result is a business plan towards 2028 that provides strong and profitable growth while generating robust free cash flow and attractive returns through the plan period. First, I will summarize our 2020 financial performance. Obviously, the oil price collapse last year made its mark on the financials. Our realized prices were down 36% year-on-year. However, we partly mitigated this by strong increase in production, driven by on-time delivery of new projects, and by strong operational performance. We ended the year on a high note with fourth quarter production at 223,000 barrels per day. This was a new all-time high for Aker BP and brought total production for the year up to 211,000, an increase of almost 35% from 2019. Cost control is, of course, important for every company that wants to drive financial performance. Lower costs mean higher profits and builds resilience against the kind of market volatility that we have seen lately. In 2020, our production cost ended at $8.30 per barrel. This was 33% down from the year before, and 17% lower than the original guidance for the year. Most of our production costs are based in Norwegian kroner. The numbers are sensitive to the dollar-NOK exchange rate, and the high volatility in 2020 impacted our guiding through the year. We got some help from the strong dollar. Still, on an FX-adjusted basis, we delivered roughly 10% lower production cost compared to our original guidance. This was the result of intensified cost management and reduced offshore activity. Despite the low oil prices, free cash flow was more than $350 million in 2020. This was helped by tax refunds under the temporary fiscal regime. Even without those refunds, cash from operations more than covered investments as we used the flexibility of the portfolio and tight cost control to reduce capital outflow. Cash flow from financing was $74 million and was primarily driven by refinancing of existing debt and increasing liquidity headroom. Net debt increased by only NOK 154 million - NOK 3.4 billion year-on-year, down from NOK 3.6 billion at the end of the third quarter. When we provide guidance to the market, it's based on our comprehensive bottom-up business planning process. As part of our culture of continuous improvement, we always do an honest review of our forecasts after the fact. Comparing the guidance we provided one year ago with what actually happened, I think there are two points that's worth highlighting. First, capital spend, production costs, and dividends were all significantly reduced compared to the initial plan. This is a reflection of the actions we took to protect our balance sheet, given the unprecedented uncertainty caused by COVID and the following oil price collapse. Secondly, production for the year was in line with plan as we avoided interruptions, maintained high production efficiency, and kept our new projects on track. Now, let us turn to how we plan to allocate capital in the years to come. The main elements of our capital allocation framework remains the same. The framework has been clarified and adapted to reflect both changes in the external environment and the investment opportunities that lie ahead. During 2020, the three priorities of the framework were put to the test. Through actions, we demonstrated that the number one priority was and will continue to be our financial capacity and flexibility. The second priority is to invest in profitable growth, focusing now first on the opportunities that can be sanctioned by end 2022 in order to benefit from the temporary fiscal regime. Thirdly, we will return the value back to shareholders, and the ambition is to provide a reliable dividend that grows in line with our value creation. Let me start with the priority number one, our financial position. In a year with unprecedented volatility, we continued our journey of fortifying the balance sheet. In January last year, we issued our first investment-grade bonds. This significantly improved our liquidity position and gave us headroom when the crisis hit in March. In September, once credit spreads were more back to normal levels, we issued another set of bonds. In total, we issued $2.7 billion of new long-dated bonds in 2020, and the proceeds were used to repay shorter-dated bonds and drawings under our revolving bank facility. The result is, even after an extraordinary year like 2020, I believe that the balance sheet of Aker BP has never been stronger. Leverage and net debt increased only marginally in 2020, and at the same time, we increased the liquidity headroom from $2.6 billion-$4.5 billion. In the process, we also extended the average maturity of our debt from 2.2 years - 6.5 years. We have no bond maturities before June 2024, and the full $4 billion RCF is undrawn. In 2021, we will continue to optimize the capital structure and manage financial risk, taking into consideration the volatility in the external environment. This means that we will ensure to have at least $2 billion of liquidity available and continue to protect downside with a fit for purpose hedging program. Let us move on to the second part of our capital allocation framework, our investment plan. Over the years, Aker BP has accumulated a large inventory of contingent resources with low breakevens, providing a significant opportunity set for profitable organic growth. Our focus is now on the most attractive resources that we can sanction by end 2022, to benefit from the temporary fiscal regime. This is 10 - 12 projects, depending on how they are grouped, representing 550 million barrels of oil equivalents net to Aker BP. The hurdle for sanctioning these investments is that they have a positive NPV10 at $30 Brent. Currently, the weighted average internal rate of return of these prioritized projects is above 25% at $40 Brent and above 30% at $50 Brent. As these projects are all targeted to be launched within the temporary fiscal regime, they will benefit from accelerated tax depreciation. Year one tax deduction is roughly 73% compared to 16% in the ordinary regime. The impact is both a significant shift in breakevens across the project portfolio, thereby improving the profitability, and a significant reduction in the capital requirements. When we invest in all these projects as planned, the total CapEx is estimated to average around $1.6 billion per year over the next eight years. 80%-90% of this CapEx is related to either already sanctioned projects or the projects identified to be sanctioned by end 2022. In 2021, we also expect to spend roughly $1.6 billion on CapEx. The increase from what was indicated at our third quarter presentation is mainly driven by two things. We have succeeded in accelerating some additional production wells from 2022 into 2021, which means that they will be covered by the temporary tax system. This has been made possible by better than planned performance on plugging and abandonment of wells at Valhall. In addition, the NOK has strengthened, and we now assume NOK 8.5 per dollar for 2021 versus NOK 9 assumed back in October. On a like-for-like basis, this increases our investments measured in dollars. Roughly 40% of CapEx in 2021 is related to Valhall, including the Hod project, 15% is related to Alvheim, and roughly 10% each to Johan Sverdrup phase II and Ula. If we take a look at the same profile after tax, we clearly see the effect of the temporary fiscal regime. Accelerated tax depreciation means that the capital required to finance these investments is reduced by 50%-60%. Although the average CapEx is $1.6 billion per year, the average post-tax cash outflow is estimated below NOK 400 million per year in the same period. If we deliver on this hopper of new projects, our production is expected to grow to more than 350,000 barrels per day by 2028. This compares to our 2021 production, which is expected between 210,000 and 220,000 barrels per day. The biggest contributor in 2021 will be Johan Sverdrup. Together with Valhall and Alvheim, these three assets will make up roughly 70% of the 2021 production. Looking beyond 2021, we expect a step-up in production in 2023 with a full year of production from Johan Sverdrup phase II. Additional new projects will keep production relatively stable in the period up to 2027 when NOAKA is planned to start production. At the same time as we invest to increase production, we continue our effort to drive down underlying costs. Significant steps have already been taken. Production costs in 2020 was at an all-time low for Aker BP. We expect to see further effects of the work with our new operating model in the years to come. Many of these have not yet been included in the business plan. Our ambition of reaching $7 per barrel in production cost is challenging, but is definitely within reach. In 2021, we expect production cost per barrel to average between $8.50 and $9. This is slightly up from 2020 and driven by the Norwegian krone strengthening against the US dollars from realized $9.40 in 2020 to assumed $8.50 in 2021. Underlying costs are expected down year-over-year. As always, exploration provides additional upside to the business plan as no new discoveries are included in the production profile, but the estimated costs of exploration are included. At the same time, our exploration spend is highly discretionary. This was clearly demonstrated in 2020 when we postponed a lot of activities. Now in 2021, many of those activities are brought back. The expected 2021 exploration spend of roughly NOK 400 million- NOK 500 million is highly impacted by our field evaluation work on capital projects that have not yet reached a formal concept selection. Planned spend on field evaluation is almost NOK 200 million in 2021, where roughly 50% is related to the NOAKA project, with a targeted concept selection mid-year. Going forward, our plan is that 80% of our exploration efforts is spent on prospects close to existing infrastructure, and total spend will of course then depend on the opportunity set available. Abandonment spend for Aker BP the next eight years is limited, with an an estimated average spend of less than NOK 100 million per year pre-tax. 85% of this is related to Valhall, and two-thirds is plugging and abandonment of old wells. In 2020, we have seen a further improvement in performance on P&A, enabling us to finish the 2021 campaign at Valhall several months before the original schedule, freeing up time to use the rig for more value-creating activities. Total spend in 2021 will be roughly NOK 200 million, where most of it is related to the mentioned Valhall program, but also some costs are related to slot recoveries for new production wells at Ula. In combination, the updated business plan profiles generate a robust free cash flow across various oil price scenarios. In 2021, we expect to be free cash flow breakeven at a Brent oil price around $35. This is slightly up from our expectation of roughly $30 at our third quarter presentation, and two of the three main drivers have already been mentioned. We accelerated investments into 2021, and the Norwegian kroner has strengthened. In addition, free cash flow is impacted from less tax refunds in the first half of 2021 for the fiscal year 2020 as the oil price finished off stronger in 2020 than what was originally expected. Longer term, even in a $40 price scenario, we estimate to have positive free cash flow in almost every year without adjusting the activity level, and this is through a period where we are investing significantly in profitable growth. At oil price level closer to where we are today, the plan generates significant free cash flow, even in the most CapEx-heavy years of the NOAKA project. The third element of our capital allocation framework is how we as a company think about returning value creation. A central part of this is our updated dividend policy, developed together with the board of directors. The policy's purpose is to support our goal of maximizing long-term value creation, and the key principle is that dividends shall reflect the distribution capacity through the cycle, considering the long-term financial outlook and the credit profile of the company. Furthermore, cash dividends is the main vehicle for distributing value back to shareholders. For 2021, the proposed dividend is $450 million, up 6% from the total dividend paid in 2020. The 2021 proposed dividend sets a floor for future dividends that together with the updated business plan up to 2028 is robust down to at least $40 Brent through the period. For oil prices above $40, the ambition is to increase the floor by at least 5% per year. If we experience a sustained oil price below $40, we will reassess our investment plan and the distribution level to align with underlying value creation. In accordance with a defined pecking order, the first priority will be to maintain financial robustness and our investment-grade credit rating. Furthermore, a review of what constitutes a profitable investment for Aker BP will be done to safeguard that value is created from our investments. For oil prices above $65, extra shareholder distributions will be considered together with reducing debt. The current investment plan, including financing cost, is estimated to be free cash flow breakeven below $30 Brent accumulated in the period from 2021 to 2028. Including a dividend similar to the proposed 2021 level, the business plan is estimated to be free cash flow breakeven post dividends below $40 Brent. With oil prices between $50 and $65 per barrel, the additional financing capacity for distributions and debt reduction is estimated between 70%-150%. Now, combining it all, the full capital allocation plan the next eight years. This is what the balance sheet could look like through the period. Even in a scenario where the oil price would drop to $40 Brent and stay there through the whole business plan period and we make no adjustments to the plan, we will maintain what we believe is an investment-grade credit profile. In a $40 environment, we will reduce leverage from today's level over the planned period, and only in short periods exceed our internal target of 1.5 net debt to EBITDAX. This is while we, at the same time, invest to grow production above 350,000 barrels per day in projects with break-even below $30 spent. We continue to explore close to our existing fields to refill the resource hopper. We return significant value back to society, both through our investments and also by paying over NOK 7 billion in taxes over the period at the current oil price level. Last but not least, while we steadily distribute value back to our shareholders through dividends. Here illustrated with a 5% increase per year from the proposed 2021 level of $450 million. To round off, let me summarize our guidance for capital allocation in 2021. We expect to produce between 210,000 and 220,000 barrels per day, which is a couple of percent increase from the 2020 level. We will likely start the year slightly above this range, and in the second quarter, we expect to produce below the range due to summer maintenance and turnarounds. In the third and fourth quarter, production is again expected to be within the range. We expect total investment spend pre-tax of NOK 2.2 billion-NOK 2.3 billion, where NOK 1.6 billion is CapEx, NOK 200 million is abandonment expenditure, and approximately NOK 400 million-NOK 500 million is classified as exploration expenditure. In-year phasing will be stable, but a bit heavy in the second quarter with slightly above 30% of the spend. The rest is evenly distributed between the quarters. Production cost is expected between $8.5-$9 per barrel, assuming an exchange rate of NOK 8.5 per dollar. Lastly, the proposed dividend for 2021 is NOK 450 million paid out in quarterly installments. Before closing off, I would sincerely like to thank all of you for the support in 2020. Last year, we met with more investors, bankers, analysts, researchers, and other key stakeholders than ever before. Although not face-to-face, but on numerous video and telephone meetings and conferences. Your support through engagement, encouragement, and challenges continues to be instrumental for us, and I sincerely hope to see all of you again soon. I would like to thank you all for your continued interest in Aker BP. I do hope that you have found today's presentation useful. Let me round off with a brief summary of the main messages today. Aker BP will remain a pure-play oil and gas company. Our contribution to the energy transition will come through maximizing value creation, minimizing emissions, and by sharing data and competence with other industries. Our emissions are already among the lowest in the industry. We will drive them further down. We are operating our assets with high efficiency and low cost. We are well on the way on our digital journey. Going forward, one of our main priorities is to implement our new operating model to further improve efficiency, cost, and safety. In cooperation with our alliance partners, we have established a world-class project execution capability, and with the new digital execution model, we will take this even further. These capabilities are essential to Aker BP as we are now embarking on a string of projects to develop more than 500 million barrels of new resources over the next couple of years. With break-evens well below $30 per barrel, these projects will create significant value. Finally, with robust cash flow generation and a supportive tax system, we will deliver on all three of our financial priorities. We will maintain sufficient financial capacity, we will invest in profitable growth, and we will return the value creation to our shareholders through a sustainable growing dividend. In sum, this is why we think Aker BP is now uniquely positioned for value creation. Good morning, everyone. This is Kjetil Bakken, I'm Head of the Investor Relations team here at Aker BP. I would like to thank you all for tuning in to Aker BP's Capital Markets Update today. Due to the COVID situation, we had to do things a bit differently this year. We sincerely hope that you have found it interesting so far. The next point on the agenda is the Q&A session, which will start at 10:00 A.M. European time. There are two ways to participate in the Q&A. You can either participate on the call by following the dial-in instructions on the screen. You can listen in to the call by staying on this webpage and submit your questions by email to ir@akerbp.com. The Q&A session will last for one hour, and if your questions do not get answered or if you have any follow-up questions, we in the Aker BP Investor Relations team are at your service. The sound will now be muted until 10:00 A.M. Stay tuned. Hello, I'm Kjetil Bakken, the Head of Investor Relations at Aker BP. It's my pleasure to welcome you all to the Q&A session of our 2021 Capital Markets Update. Since COVID prevents us from hosting a physical event this year, we have chosen a different approach, and I really hope that you liked it. With me in the room today, I have our CEO, Karl Hersvik, and CFO, David Tønne. We also have our Head of Operations, Ine Dolve, and our Head of NOAKA, Lars Høier, on the line from separate locations. This Q&A session is scheduled to last for one hour. If you have any follow-up questions, please do not hesitate to contact us in the investor relations team. With that, we hand it over to the operator to open up for questions. Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, that's star one to ask a question. We'll now take our first question from Yoann Charenton from Société Générale. Please go ahead. Your line is open. Good morning, everyone. Thanks again for the presentation this morning. I would like to thank you as well again for the transparency of projections you share with us, and I would have three questions if you don't mind. The first two questions are on production profiles. The first one will be about the Valhall area. I understand that there is a certain degree of certainty that is associated with this newly unveiled production profile for the Valhall area, and I would like to get a better understanding of how strong it is. How confident were you with your prior production outlook when it was presented last year, and what has changed since then? The second question on production profiles again, will be more focused on the Ivar Aasen area. This is clearly your most recent production add. You have invested billions in the platform. If we look at these projections that you are showing today, at least it appears that this platform, unfortunately, does not have the right postcodes. The field is depleting quite quickly. I would like to get some color on how much surprise there is for this production profile to be reassessed in the future. My third and last question would be on a different topic, which is carbon capture and storage. This appears to be of great importance to Norway's government. Do you have a mandate to play a role in the development of carbon storage within the Aker galaxy? Thank you. Thank you, Yoann. Maybe I can answer your questions. First, on the Valhall production profile. First, let's remind everybody that Valhall is a pretty big field. It's a gigantic field. We're expecting to produce more, 300 million barrels now, but we're expecting about a billion more out of this field. It's also a highly complex field. It's a field where we have historically, that is after 2016, been testing a lot of technologies to support that long-term ambition. Some of these technologies have not proven entirely successful, and we've been working on rectifying that as we've discussed in this forum before. For example, the single-trip multi-frac, which is now working. My view on this is that the Valhall production is pretty much in line with our internal expectations, and we may have been a bit optimistic previously. There is a lot of work ongoing to rectify the current issues, and I'm confident that we will be back on track soon. Of course, all these technologies are actually really value creative for a long-term development of the ambition on the Valhall field. While we have been working quite ambitiously on discovering new technologies, single-trip multi-frac, new lower completions, multilaterals in chalk, digitalizing chalk influx, et cetera, I think this will prove crucial when we look at the longer-term ambition on the Valhall field. Your comment on Ivar Aasen. If you look at the presentation that we have put out there on slide 26, you will see the production profile. You're right, there is a certain decline from 2020, which is all planned and pretty much following the original plan as communicated also in the PDO. We have recently approved the drilling of two IOR wells in 2021, which will increase production in 2022, 2023, and 2024 compared to the existing decline, which will offset decline at this field significantly. Your comment on CCS. Our strategy when it comes to climate change and let us say renewables and also accounting for CCS is that we will support these developments, but we do not necessarily attempt to participate or directly invest. As you may have observed, Aker has recently launched the Aker Carbon Capture this summer or last summer and is now expanding that portfolio. There might be investment opportunities, particularly related to storage in either existing Aker BP fields or Aker BP fields in the future. In that case, we will come back to that. When it comes to the broader CCS picture, I see CCS as an important technology, particularly related to electricity production from hydrocarbons in the future. We're highly supportive of that trend. At this point in time, we see that there are other CO2 reduction mechanism that gives a higher yield, and is more important to the Aker BP investment. This is very clear. Thank you. We will now move to our next question from Teodor Sveen-Nilsen from SB1 Markets. Please go ahead. Your line is open. Good morning, thanks for taking my questions. Thank you for a very good presentation. Two questions from me. First one on the dividends, which I guess has been a hot topic ahead of the Capital Markets Day. You said that you expect dividend to grow by value creation, which of course is nice. How should we interpret that? Will future dividend be a function of EPS, so free cash flow or some kind of internal NAV estimate? Second question is on NCS M&A market. I guess you will still only be on NCS, so that will be important for you. Is it still fair to say that it's a buyer's market out there? Any comments on that would be very helpful. Thank you. Thank you, Teodor. I think I'll hand over to David on the dividend, and then I'll reflect a bit on the M&A question, both in regards to the current market and also Aker BP strategy. David, if you want to expand on the dividend question. Sure. I'll do that, Karl. Thank you, Teodor. On the dividend, we put forward a pretty clear framework for how we're thinking about dividends going forward. As stated, the underlying goal of Aker BP is to maximize long-term value creation and the three capital allocation priorities remains the same. When we talk about following the underlying value creation, we're talking about the value creation through the cycle as we are growing production, and thereby also free cash flow. We haven't linked the term value creation to any specific financial metric. As indicated with the different oil price scenarios in the presentation, we expect or have an ambition for dividends to grow by at least 5% in an oil price environment between $40 and $65 Brent. Yeah. On the M&A. Well, of course, after the temporary changes to the tax system, I think most of the CapEx projects in Norway changed appreciation. Of course, that relates primarily to the project inside the temporary tax system. That is for those with a PDO to be delivered by the end of 2022. Our strategy when it comes to M&A remain unchanged, Teodor. We haven't really made any modifications to this essentially from 2015 and onwards, and we're still predominantly only focused on value creation, and how we can maximize value for our shareholders using M&A as a vehicle. Historically, we've been extremely active, as you know, but that has also resulted in a large hopper of highly value accretive organic projects, which we are now in the process of executing, as communicated previously today. I think the main driver right now is that most of the M&A we look at has a much lower value creation potential on the inorganic side than it has on the organic side. If you look at this as a use of cash to generate value, right now it's much higher value to be generated by investing in organic hopper, which we by the way, mostly expanded through an M&A strategy. That doesn't mean that we're not revisiting or looking at opportunities. If the NCS is a buyers or sellers market, I think at least prices, particularly on CapEx, has gone up significantly following the temporary change of the tax system, particularly for those players who can utilize those tax positions. I think right now, at least NCS is a highly competitive M&A market where we are going to be cautious. Okay. Thank you. Could I just follow up with one on the dividend question? What's the specific reason for preferring cash dividends and not buyback? Sure. I can do that, Teodor. As you stated, we're pretty clear that our main distribution mechanism will be cash dividends. The way we think about this is basically that it doesn't exclude buybacks in the future, but as sort of a policy statement, we believe that's what creates, or it's the best way of returning value, given also the fact that if you were to include buybacks as a mechanism at various oil prices, you would probably be buying back shares when the oil price is higher and the share price would be higher. For us, buybacks would not be viewed as a distribution mechanism, but more an investment opportunity if that appears to be value accretive for us as a company. Okay, thank you. Thank you again for a good presentation. We will now move to our next question from Anders Holte from Kepler Cheuvreux. Please go ahead. Your line is open. Thank you, guys. Thank you for taking my questions. I'd like to secondly, Teodor, congratulations on a well-held presentation. Now, obviously, the effect on the tax changes is going to have a pretty substantial impact on the net free cash flow going forward as we look at your investment plans. I get that all the CapEx this year is going to be covered by the tax changes in place. The key question becomes how much of your future guided CapEx that you see on your long-term guidance will be covered by the tax amendment that's now available for projects that are ready for plan and development and operations handed in next year? Just to simplify, to know how much going forward is related to projects that are eligible for the tax change. Thank you. The way to look at this is that 80%-90% of our CapEx that's included in this plan is either related to already sanctioned projects or projects that are going to be sanctioned with FID before end 2022. That means that most of this CapEx will be eligible for the temporary fiscal regime. We've also done you the favor of actually calculating the post-tax cash outflow on page 53 in the presentation, and there you definitely see the effects of this. Okay. Thank you. That's very clear. We'll just pause here to ask the speakers whether any questions have come in over the web. Yes, there is. We have one question here from Mark Wilson of Jefferies. He has a question on the longer-term production ambitions. It would appear that around 50,000 barrels per day has disappeared from the underlying plan, and particularly the non-sanctioned part. At the same time, NOAKA has got larger. The second question, I'm not sure if that was a question, but we will see. The second question would be details on the appraisal of Liatårnet. What is the current range of resources? What does success look like? Is a flow test included, and do you expect to farm down ahead of that? I guess that's a question you can start off, Karl. Yeah, I can certainly try, Kjetil. Thank you. Let's start with the production, Mark. No barrels have disappeared, but what we have done is an optimization of the production of the project in the hopper where we've basically focused on maximizing value, but also on making sure that the project we do execute have a sufficient maturity as we reach the end of 2022. Most of these barrels are directly linked to King Lear, which is a high-pressure, high-temperature project, which will require maturity and time before we reach a PDO. Our assessment was that there were better investment opportunities generating higher returns in that portfolio, and we have therefore delayed the King Lear project to maximize both value, but also to minimize risk in the portfolio. That does not mean that the King Lear has disappeared. It means that it's been pushed out. We have delayed that project. I think from my perspective, this is about making the execution plan more robust as we're now speeding up a lot of the early phase project to put them inside the 2022 hopper. Let's just remember that the key to robust and successful project execution is a good early phase. The groundwork we're doing now is the basis for a solid execution post-2022. On Liatårnet, the resource estimates are largely unchanged. This is a rather shallow reservoir. It means that the seismic response is quite good. We understand fairly well the size of the container. The big questions are now related to oil quality and how we can design the PdQ at the Noaka field to receive this oil. What we're looking for is not necessarily a flow test, but we are looking for a sample of sufficient size to update our design profile on the. NOAKA project. Of course, or not necessarily of course, but we don't plan any changes to ownership on NOAKA. Yes, I guess that is a good answer to Mark’s question. Operator, we pass the word back to you. Thank you. We'll now take our next question from Al Stanton from RBC. Please go ahead. Your line is open. Yes, good morning, guys. Well done for a very polished presentation where every word, I think, was chosen with consideration. It's interesting that you never used the phrase net zero. I would have bet my house that senior management, even in an elevator pitch, would use the phrase net zero in any discussion about their strategy going forward. I'm wondering, have you deliberately not mentioned it? More generally, what is your strategy towards achieving net zero? Thanks, Al, and I love your comments about my trainers, by the way. I think our strategy when it comes to the transition and the energy change is quite clear. We will remain an oil and gas company. We will focus on optimizing our portfolio and reducing our emissions, and we will contribute to the energy transition by, I would say, participating in value creation in these value chains. Net zero is essentially a way of optimizing your cash portfolio. To me, the most value to be had right now is to minimize emissions, and that's what we're doing. If you look at our portfolio, we will reach net zero, as a matter of fact. We will reduce our CO2 emissions by about 50% in the 2030s, and by 2050, we will be virtually net zero, as a matter of fact. My view on this is that we invest where we can maximize efficiency of those investments when it comes to amount of CO2 reduced per US dollar or per NOK. Right now, that is not necessarily on the offset side of that equation. It's simple as that, Al. Right. I suppose my concern then is whether you think the audience accepts virtually net zero in 2050 is good enough given the amount of pressure that I'm seeing on your peers who are embracing offsetting and other initiatives to achieve net zero much more quickly? I think that's a good question. I think so far we've had a lot of positive feedback on the clarity and direct strategy. Of course, there are opportunities to reach net zero more quickly if that is believed to be a value later on. It doesn't necessarily mean that we can't do it just means that there are better ways of investing those money rather than reducing CO2 emissions in Aker BP. Okay. Thank you. We will now take our next question from Matthew Smith from Bank of America. Please go ahead, your line is open. Hi, yes. Morning, everyone. I think the key questions have already been asked, to be fair, I'll just go for a quick clarification on the dividend, if I can. Just to be clear, the 5% minimum annual increase, that minimum phrase, that applies to oil prices between the $40 and the $65. Is that right? There could be upside to that 5%, even without oil prices above $65. Am I reading that right? Yeah. The way to read it is that we have an ambition to grow dividends by minimum 5% at oil prices at or above $40 Brent. Then we are also indicating in our framework that above $65 Brent, you could consider also extraordinary dividends on top of that. It's basically lifting the floor by minimum of 5% as an ambition of oil prices above $40. Then I think just to make it very clear, what we have done here is basically put in plan a financial framework which is robust down to at least $40 Brent, including the investment plan that we have. Of course, what we're solving for is the number one priority in our pecking order, which is the financial robustness and our investment-grade credit rating. Secondly, of course, then investing in profitable growth, which makes a lot of sense given the opportunity set that we have available. Sure. Thanks. That's clear. We'll now move to our next question from Chris Wheaton from Stifel. Please go ahead. Your line is open. Gentlemen, thank you very much indeed for an excellent presentation from you this morning. I would have expected nothing less. Two questions, if I may please. Firstly, can I go back to Mark Wilson's point on NOAKA? Your future production slide shows quite a substantially bigger project than I thought. Peak production in excess of 150,000 a day in 2028. If the ownership of NOAKA hasn't changed, which I don't think it has. Could you talk about what's driving that bigger project upside versus before? Secondly, a question about managing all the CapEx and the projects you've got to sanction before the end of 2022. A lot of the strategy today you've outlined is because the Norwegian tax changes have enabled a really very attractive window of growth opportunities to open up for you. You've got to deliver a lot of project definition and a lot of project scope work before the end of next year to get things sanctioned, to get access to that advantageous tax structure. Also, once you've delivered them, you can't all execute them at once. Is there an issue, could there be an issue that there could be quite a delay between sanctioning the project in the next 18 months and then actually finally spending the money, let's say 2025, 2026? Is the Norwegian government going to be okay with that kind of extended delay between taking advantage of the tax break and actually spending the money? Thank you. Thanks, Chris. Maybe Lars, I will hand the NOAKA question over to you since you are the guy actually running that show. Thank you, Karl. Yeah, we are working full time with our alliance partners and also with the license together with Equinor and Lotos to find the right concept, and we are in the middle of the concept development phase now. That's really interesting to see how we can optimize the production. We are in the middle, and we are also working with the right number of wells. It's too early to say too much on the production level. We will work hard to optimize it, and we will take a final investment decision, end by 2022, fourth quarter. We'll come back to it in more detail when we have the right solution and optimum solution. Yeah. Can I just have one follow-up at that point then, please? Because what is the scenario that's represented in the disclosure you've made today? Is that a base case? Is that the most likely case for that 150,000 a day net to you in 2028? Thanks, Chris. Just to be clear, what we have done up to now is optimizing the concept as Lars was just discussing. The case represented in the material released today is what we believe to be most likely at this point in time. Of course, as Lars also pointed out, we're in the middle of the project development phase. We can't exclude that there will be any changes, but this is the most likely case as we see it today. I'll just to add one point from my side as well. I think it's important to note also where we were back in 2020 at our previous Capital Markets Update with regards to discussing also commercial arrangements also with our partners. What was assumed in the business plan in 2020 was roughly a 50% ownership share in the NOAKA project. While what we're including here now as stated on the slides is basically our share of the different licenses, which is included in NOAKA, which then accumulates to around or above 60%. That's also a part of why there is a bit of a difference in the size of NOAKA on the slides. Thank you, David. Your last question was the crucial one, which is about capacity. Let me guide your attention to our previous discussion in several of these capital market days around alliances, where we spent a considerable amount of time explaining why and with whom and how we set up these alliances. Just a very short recap. We have now established seven alliances across the value chains from projects to drilling and into brownfield modifications and well maintenance, now topside maintenance work. I must admit that once we established these alliances, the primary driver was to optimize cost and reduce error and time. As we're now growing the portfolio, we also see that these alliances allow us a far higher execution capacity than would otherwise have been possible. The simple fact is that by these alliances, where we worked with a lot of these partners over quite a few years now we have established an execution mechanism that doesn't necessarily rely on a growing Aker BP organization. In many ways, this alliance have actually been a foundation for the execution strategy, which proves far more scalable now than the previous execution strategy we had before the alliances. It also allows us direct access and priority to resources in the market. It means that even if the market is heating up, particularly on, I would say, engineering, drilling, and well related services, et cetera, that doesn't necessarily impact our execution strategy. In many ways, you could probably say that this was luck, Chris, but I think we actually ended up in a really good position when it comes to the execution both in terms of scale, risk, and also management of fluctuations in capacity. Finally, your comment about plans. The current plans does not necessarily mean that there will be a delay in terms of project execution. It's not like we're ramping up delivering the PDO and then cooling down again. These projects are scheduled and optimized such that they will actually follow a pretty normal execution schedule. The questions that was asked a bit earlier today about optimization of that schedule is exactly to minimize that, I would say, delay or possibility of delay so that we can actually follow a continuous schedule. The reason is very simple, Chris, and that's if we ended up in a situation where you would deliver the PDO and scale up the organization to make a financial investment decision with all the associated engineering and technical studies and then cool off again, these people would have gone elsewhere, and the project would have been at risk. In reality, that is a very complicated strategy to execute, and we do not plan to do that. Great. Thank you very much indeed. We'll pause here again just to check with our speakers whether any more questions have come in over the web. Yes, there are. The next question comes from James Hosie of Barclays. In the future CapEx profile on slide 52, NOAKA is clearly the largest part of the 2022-2028 spending plans. How wide is the range of uncertainty in the budget for that project today? Second question, in the free cash flow outlook, slide 60, we see it declining in 2023-2025 such that the $50 per barrel, the dividend would not be covered by free cash flow. Is that a constraint on your capacity to raise the payout by more than the 5% minimum in 2022-2023, regardless of the oil price? I guess that last question goes to you, David. The first question, I guess, Karl could take. Yeah. If you take the last point, and I can comment on the NOAKA expenditure later, David. Yes, I can do that. I think the quick answer to that is that the dividends that we will pay will reflect the distribution capacity through the cycle. Considering the financial outlook of that. Our plan now is robust at $40 Brent. We have an ambition, as already stated several times today, to grow that by at least 5% if the oil price is above. Of course, we will take a holistic view on what that increase will be in any given year. The investment period with NOAKA in 2024, 2025 and that impact on cash flow in such a scenario will not have a significant impact on our ability to pay the planned dividend. When it comes to uncertainty in CapEx, of course, as we are progressing these studies and getting more market information about the cost of each of these elements, the uncertainty range will decrease. I think it's a bit immature to state explicitly what kind of ranges we're looking at at the moment as the project components are in a bit of a different stages. We'll come back to that a bit later on. Just to remind everybody that we're delivering the DG2 in September this year. At that point in time, we will provide much more clarity both in terms of cost and uncertainty and estimates. Thank you. While we are on this line, there is another question here from Anne Gjøen of Handelsbanken. With focus on your peak production level in 2028 above 350,000 barrels per day, can you comment on the range of CO2 emissions among your main fields and how much you expect to pay in CO2 tax when you reach peak production compared to the level of today? I guess, David, this is one of your favorite topics, so I'll pass the word to you. I think that's one for you, David. Everything that related to tax is probably your field of profession. Yeah. Thank you for that, Karl, and thank you, Anne. Just to recap a bit, of course. Valhall is, of course, already electrified with power from shore. Ivar Aasen will be electrified with power from shore as part of phase II of the Johan Sverdrup field development. The NOAKA project will be powered from shore. If you take that as a starting point, it's basically Alvheim, Ula and Skarv, sorry, which are the three assets which has the highest CO2 emissions per barrel since they are not powered from shore. They will stand for most of the CO2 emissions at peak production. When it comes to the CO2 taxes that will be paid, we have outlined that in our presentation when we're talking about production costs. What you can see there is that in absolute amounts, it's relatively flat over the period. One of the reasons for that, of course, is that we are working to reduce CO2 emissions as we also increase production at the same time over that period. You are talking roughly $1, $1.50 maybe in production cost per barrel at peak production in terms of environmental taxes. Remember, this includes then both the CO2 taxes that we pay to the Norwegian authorities and the quotas that we pay. The assumption is aligned with the Norwegian government's updated target of paying NOK 2,000 per ton in 2030. That being said, Anne, there are studies ongoing, both related to electrification on Skarv and other, I would say, large-scale CO2 mechanism. The key issue for us is to assess whether that is the best use of capital when it comes to minimizing CO2 footprint. On behalf of Anne, I thank you very much for those fantastically good questions, and leave the word back to the operator. Thank you. We will now take our next question from Sasikanth Chilukuru from Morgan Stanley. Please go ahead. Your line is open. Hi. Thanks for taking my questions. I had two related ones, please. I just wanted to go back to the production outlook and your production ambition. You have pretty much the peak production coming in at 2028. I was just wondering is that the ambition for the company now for that production level to be at in going beyond 2028? What is the ambition now of a sustainable production level that the company is looking at? Related to this, do you have the resources available right now to support that sustainable production level? Should we expect CapEx to increase over the next few years, especially for 2027, 2028, over the next few years, as we have more clarity on how you would actually get to that production level? Yeah. Okay. I think it was breaking up a little bit, Sasi, but I think what you asked is if the production level we're now guiding for around 350,000 barrels, and do we have the resources to sustain that for a long period of time? Of course, then the associated CapEx with that production profile. Would that be correct? Yes. Also, what is the ambition of the sustainable production level? Is 350 the benchmark or is it lower? Thanks. Let's take those in sequence. I think if you look at the production slide on page 32 in the capital market presentation, that will demonstrate, as we usually do, the outlook up to this point in time, 2028. You see the growth up to about 350 and a little bit above in 2028 with NOAKA coming on stream. Of course, this represents a little bit more than 500 million barrels of the 2C hopper. There is a healthy amount of reserves that are not included in that production profile. Right? There are several discoveries we have not put into the 2C reserves either because it's immature. There was a previous question around Liatårnet, which is not included. There might be other discoveries that are in the early phase that are not reached to 2C. Going back to our previous statements a couple of years ago, that we only included project in this portfolio that we can name. Of course, that is also the clue to the second question. If you're reaching 350,000 barrels or more, there's a significant resource replacement challenge, particularly in the long term. Right now, there are about 900 million barrels in total in the 2C, so the math is pretty simple. Of course, there is a gap as you're approaching 2030 or mid-2030s if you are going to sustain 350,000 barrels. The math of that is actually quite simple. The CapEx profile is also outlined in the material. Of course, with that CapEx profile, which is directly associated to the project we are now planning to execute, it's also a significant decline in CapEx as you're maturing this project and then executing them associated with a production profile. Right now, I think we have a very healthy outlook. I don't think there are many companies out there with roughly 200,000 barrels of production, or a little bit more, and then 900 million barrels of opportunity set already in the hopper. At the moment, my primary focus is not necessarily on what happens post-2028 or 2029 or mid-2030s, but it's making sure that the value is maximized inside that existing hopper. There was another question related to M&A. Historically, we've been growing our asset base significantly through M&A. You can also see from the material that there is sufficient and significant cash flow generation as we're maturing this project and CapEx is dropping off. Right now, I would say I'm comfortable with the position. Of course, you can calculate out there is a reserve replacement issue post, I would say, mid-2030s. Thank you. We'll now move to our next question from James Carmichael from Berenberg. Please go ahead. Your line is open. Oh, hi. Thanks, guys. It was actually asked earlier, mainly on the carbon taxing issue. I guess just as a quick follow-up, I'm interested to get your ability to hedge against any of that carbon price rise that you've outlined in the presentation. Is that something you can do? Something you plan to do? That would be helpful. Thanks. I think the simple answer to that is currently no. The way that we think about this, that it's an incentive to reduce emissions and that's how we plan to cater for that. Ine talked a lot about, during her presentation, around the initiatives that we have for energy optimization. That's the general thinking around it. Then, of course, the projects that Karl referred to, for example, larger scale investments in power from shore to a Skarv would, of course, also significantly reduce those taxes. I think the taxes that the Norwegian authorities are putting in place on CO2 emissions are not necessarily something that we've looked into hedging. I'm not sure how we would do that. I'm not really sure you could hedge the tax position. You could maybe buy quotas, if you expect that price to go up and create some sort of derivative around that. I think our primary driver to this is to react to the incentives that are being put into the financial framework on the Norwegian continental shelf. Rather than speculating how we could hedge out of these incentives, we're working on minimizing the impact by reducing CO2 emissions. Great. That's very clear. Thanks. We'll now move to our next question from James Thompson from JP Morgan. Please go ahead. Your line is open. Great. Thank you very much. Good morning. Karl and David, thanks very much for the presentation. Very creative. I have three questions if I may. I'll just start the first one. Obviously, NOAKA is a crucial part of the medium-term investment case. The project itself is complex. The timeline of the project has slipped over the last four or five years as it's kind of changed form. You're looking to sanction it right inside the deadline on the tax regime. Given it's so important to the outlook, would you still sanction the project if you don't make Q4 2022? Obviously, questions have been asked about capacity, but if PDO can't be taken before the end of 2022 and you don't get the tax benefits, will you still sanction NOAKA to keep to that 2027 timeline? That's my first question. Yeah. Just ask all your questions and I can answer them in sequel. I think that's probably best, James. Yeah, sure, Karl. The second question was just on the liquidity position, we've got NOK 4.5 billion of available liquidity. Looking at the medium-term CapEx outlook and the dividend that you've committed to, and your comments really on inorganic being not really the flavor of the month from your perspective, I just wondered what the rationale was to maintaining that level of liquidity. Only 2025 is the point in time where it might not be twice covered on your investment plans and your capital return plans. What's the rationale there and should we expect you to shrink the RCF over time? Would be the second question. The third one really is a math question. When I look at your reserves and resources you reported end-2020 versus end-2019, you got 2P down 64 million barrels, 2C reserves down 36 million barrels. A total of 100. You produced 76 million barrels in the year. Could you tell me what's changed in your reserves reporting? Where's the 24 million barrels lost from? Thanks very much. Thanks. Really good. NOAKA. I think the fact of the matter is that we've been working on this for a long time, and finally as we were exiting the summer last year, we got significant momentum and traction. That means that a lot of the groundwork in terms of subsurface, et cetera, is already being done. In the movie today, Lars also demonstrated that well planning is far advanced, supported by digital tools. I think what I'm looking at right now is a rather robust plan when it comes to executing up to the PDO. Right now, my primary risk associated with NOAKA, is not related to not delivering the PDO. Would we still do NOAKA if we could not deliver? I think that's a bit of a hypothetical question. I can assure you that we are going to do everything we possibly can to deliver the project inside that tax regime. That's where all our focus is at the moment. To your liquidity, and I'll hand that over to David. When it comes to the 2P and 2C, we have about 13 million barrels in increase in 2P related to revisions. Then there are, as we discussed previously, some optimization that has been done on the 2C reserves as we've been pushing some of them out in time associated with execution of these early phase projects. Then, if you remember back in March, we pretty much stopped everything that was associated with the CapEx outlay and prioritized the financial stability and the financial health of the company. That basically meant that we prioritized cash flow over reserves generation. That means we stopped a lot of these projects that would normally have been associated with increase in 2P and 2C reserves. If you start looking at that over time, this will even out, particularly as we end 2021 and end 2022, you will see a lot of these volumes coming back into the plan and into the survey and resource equation. It is a direct result of both the stop in project back in March and also the optimization of the plan associated with execution following the temporary changes to the tax system. On the liquidity question, I think it's a good question. Of course, reflecting over what's happened the past year, I think it's clear that having a large liquidity headroom has really served us well. That being said, of course, we have the NOK 4 billion RCF now undrawn, and in addition, we have more than NOK 500 million of cash at hand. That's something that we're continuously evaluating how to optimize the balance sheet. It's worth noting that we have a couple of bonds which are callable this year. Of course, half of the NOK 4 billion RCF is a working capital facility that we can choose to draw on or not. Of course, we can also downsize that if we may. Our policy is to have at least NOK 2 billion of liquidity available at any point in time. There's quite some headroom related to that. Of course, also remember that we are moving into an investment period, where we're going to invest quite heavily in profitable growth. Having liquidity is always a good thing, and we've learned that through the period of very high volatility this year. I think that the last point is important to stress. We previously said that maintaining a pretty high liquidity reserve is, I would say, a cheap way of creating insurance around our financial position. All the way back to 2015, we've had as a strategy that we should maintain sufficient liquidity to do what we needed to do, not what we were forced to do. You might see some optimization to liquidity position going forward, but the main strategy is unchanged. Okay. Thanks for all the answers. Just in terms of following up on your NOAKA comment there, is there a scenario where the southern part or the northern part of NOAKA is sanctioned at a different time to the other one? i.e., your operated bit could be sanctioned before the end of 2022, and the Equinor one might be later or vice versa, given that they are independently operated under one development plan? It's one coordinated field development. There might be sequences in terms of actual execution of the project, but I don't foresee a situation where the investment decision or the delivery of PDO is done independently. No. Okay. Thanks very much, Karl. Appreciate that. Hand it over. I'm going to just pause here again just to check with the speakers whether any web questions have come in. No further questions on the email that have not already been answered. Thank you. In that case, we'll now move to our next question from Michael Alsford from Citi. Please go ahead. Your line is open. Yeah, hi there. Just wanted to follow up on the Barents Sea comments earlier in terms of exploration. I guess one specific project or prospect you're drilling in 2021 in the PL858 out in the southeastern Barents Sea. It looks pretty small from the headline pre-drill estimate. I just wanted to understand a little bit more about the route to commerciality if it is successful. Secondly, I guess more broadly, are we thinking this is going to be an end to the Barents Sea exploration program over the medium term after the next two wells have been drilled? Yeah. That's good questions. The two remaining commitment wells we have in the Barents Sea is in PL858 which is the Stangenestind well operated by Aker BP, which is probably what you refer to as the East Barents Sea. We have the Shenzhou in PL722 operated by Equinor. The Stangenestind was one of three areas which were considered highly attractive back in the 23rd round, where Aker BP won operatorship. After that, we've reassessed both the migration, the reservoir quality, and the potential for volume. As you can see, downgraded the pre-drill volumes quite significantly. It is a commitment well, and as I stated in the video previously today, we have that and Shenzhou left, and then we'll reassess the entire Barents strategy. It's also quite clear that the results so far in the Barents Sea have been disappointing. Also that there's quite a lot of momentum, I would say, in the stakeholder picture around Arctic oil and all of those discussions which have led us to reassess. I don't think you'll see us very active in the Barents Sea going forward. Of course, if we are lucky and there is, of course, a small probability that one of these wells will turn out to be a standalone field development, then you might end up with a commercial project. Right now, I probably see this more as a commitment to drill something that we committed to in the 23rd round. Thanks, Karl. A follow-up if I could. Just a quick question on the portfolio. You obviously did a strategic review and the business plan is what we see today. I'm just wondering if there's any non-core assets in the portfolio that you've identified that perhaps you could see early monetization of. Thanks. Yeah. When I alluded to optimization in terms of execution, that of course begs the question if there are other operators with capacity or desire to execute the project that we have not prioritized, which is one of the topics we will explore going forward. Okay, understood. Many thanks for the presentation. We'll now move to our next question from Karl Fredrik Schjøtt-Pedersen from ABG. Please go ahead. Your line is open. Hi, guys. It was a question referring back to potentially beyond what you have identified in your 2C plans and what you have planned as being core investments in the near term and into the 2020, 2022 tax program. Is it so to understand that Liatårnet is the one to follow? Are there any other sizable or meaningful projects that you have not included in your 2C resource base? If so, what is the work required in order to assess the economics on these, call it almost 2C resources? That's a good term. I'll start quoting that, Karl Fredrik, almost 2C. Liatårnet is, of course, in the appraisal stage and therefore hasn't reached the 2C qualifications. There are quite a lot of, I say, Valhall upside in the so-called diatomite, if that's the right English term, which is above the main reservoir at Valhall. This is a tight field where we plan a production test. Since the flow capacity of those reservoirs are untested, we know there is oil, quite a large portion of oil, as we've drilled through this quite a lot of times. We are not qualifying that as 2C. There is a significant upside. Then there is Rondeslottet, which is a tight oil discovery, again, where we know there is oil, but the flow capacity of that field is also uncertain. All of these are going through our normal appraisal stages. That is, we are assessing their capacity, and we are of course doing technical studies to move those into the hopper. Again, let me be very clear. Apart from the necessity of appraising Liatårnet in terms of understanding what kind of changes is needed on the NOAKA project to produce Liatårnet, we are prioritizing what is already in the early phase hopper that needs to be delivered by end of 2022. There are, as you alluded to, quite a significant hopper of resources that is not now in the 2C hopper. Okay. Thank you. That's very clear. There are currently no further questions in the queue, so I'd like to hand the call back to our speakers for any additional or closing remarks. Thank you. I would like to say thank you to all of those who have been on the call today, and thank you guys for supporting us back in 2020. It's been quite a year. Moving into 2021, we're shifting gears, and we're accelerating. We're grateful for your support also in 2021. As I have the chance, I gave my IR team quite a challenge and told them that we were not going to do an ordinary CMU. What we are going to do was a production that we could show and deliver, and I think they delivered a really good result here today. I'd also like to say thank you to my IR team and the comms department who have, I think, delivered an outstanding product. Kjetil doesn't always get a lot of praise, so I think he'll be happy about that. Thank you, guys, and have a good day.