Good afternoon or morning, wherever you are in the world. Welcome to the Lundin Energy 2021 Capital Markets Day. It's going to be a bit different this year to what you're normally used to. I think probably by now, virtual events have become the norm for you, unfortunately. We're going to try and make it as in-person as possible. We've got our colleagues in Norway joining us via direct link, but we're all having to adhere to the restrictions that we've got in place in Switzerland and in Norway. The session is going to run in the usual format. Nick Walker, our new Chief Executive Officer, will take us through the context and the tone of the event, and also take us through a review of 2020, as well as looking into 2021. Our new COO, Daniel Fitzgerald, will run you through the operations and give a sneak peek on the platform for growth. We'll hand over to Oslo, where Kristin and Per Øyvind are in a studio. Kristin will take you through the pipeline of new projects, and Per Øyvind will dive into the organic growth priorities for the business in 2021. We're then going to have a short coffee break for about 15 minutes. Please don't go away too far from your screens, as our new corporate movie made by Alex Budden and the corporate affairs team will be playing, and it'll provide some light relief, and you won't want to miss that. After the break, we come back with Zomo Fisher, our VP of Sustainability, who will run you through our accelerated decarbonization strategy. Last, but by no means least, the CFO, Teitur Poulsen, will outline the financial resilience of the business and look ahead into 2021. Nick will then close the meeting. Then we'll host a Q&A session. For the Q&A, again, we'll follow the normal course. We'll take questions from the conference call line where Tracy, the operator, will direct you on that. Then we'll come back to me. I'll moderate questions from the web. If you want to do that, on the top right hand of your screen, you should see an ask question button. Please, if you want to ask a question online, please press that. If you could leave your name as well and where you're calling from, that would help me. If not, you can just send me an email, either to my own email address or we've set another one up called cmd@lundin-energy.com. cmd@lundin-energy.com if you want to ask any questions, just email me direct there. Thanks again for joining us. I'm going to hand over now to Nick Walker, President and CEO of Lundin Energy. Good afternoon, everyone, or good morning for those of you joining us in North America. Thanks, Ed, for the introduction. It's great to have you all with us today at Lundin Energy's 2021 Capital Markets Day, which we're combining today with our Q4 2020 results, which we released this morning together with our guidance for the year. Yesterday evening, we put out our release around our proposed dividends. As Ed mentioned, we're bringing this to you online. It's slightly strange presenting in a room with no people, hopefully, we can make this joined up as much as possible, together with my colleagues who are joining here from Geneva and those from Oslo. This is my first Capital Markets Day since becoming CEO, it's a real honor to step in to take the reins of this industry-leading company, I'm really excited by the opportunities ahead. I think we've got a great business, we've got a great outlook, and we've got a great program ahead. Hopefully, you can take some of that excitement away today at the end of our program. Now, I have a few slides to run through. I want to provide a bit of overview and context, and then my colleagues really are going to get into much of the detail and get under the hood of the business and share with you some of the background. Of course, we're looking forward to having a good discussion around questions at the end. First, I want to spend a little time setting some context and the business environment that we're in. I think it helps inform our strategy. In my view, the energy transition is accelerating, and we need to play our part, and we are. We need to adapt and change to stay relevant. The demand for energy continues to grow, of course, on the back of continued population growth and, as a result, economic growth. What we've set out here is the latest IEA forecast, and you can see that in any scenario, the oil and gas remains an essential element to the energy mix going forward. Of course, the world also needs to decarbonize. We need to reduce 50% reduction in emissions by 2040 and to achieve the two-degree scenario. Action is going to be required in every sector, and it's going to take time to achieve. I think the challenge is on all of us to decarbonize the energy systems while continuing to meet demand for low cost and plentiful energy that the world needs. Oil and gas has a role in the future, but we also need to adapt and change, and we need to play our part to decarbonize to stay relevant. If we now focus on the oil part of the energy equation, it's really where our business is focused. Today, the world is oversupplied with oil. We saw that last year with demand destruction and low prices, and I think we need to be prepared for price volatility going forward. I think it's important to have a business that works on downside prices. But in the long run, due to declines and lack of investment that we see, which is only exacerbated by what's happened in the last year, significant new supplies are going to be required, whatever scenario you look at. If you look at the stated policy scenario, so that's the policies that are being followed today, then we need a massive 60 million barrels of new supply per day by 2040. That's a big ask, and I think it needs to be done efficiently, it needs to be done low cost, but it also needs to be done with lower carbon emissions. These factors of low cost and lower carbon, I think, are important context to our growth strategy. My key points here are, we need to be one of the best on cost, we need to be one of the best on emissions, and if we can do both those things, I think we'll be resilient, relevant, and investable into the future. That lays nicely onto how we see our strategy. Although the CEO's changed, we're not changing the strategy. It's staying unchanged. Our focus is around organic growth. We still think that's the best way to create shareholder value. I think there's many paths to organic growth, which we'll talk about. I think it's more than that. It's complemented by having quality, low cost, low break-even price projects that deliver free cash flow generation, supporting sustainable and growing dividends. On top of that, it's about delivering on our decarbonization strategy to be a leader in carbon emissions, making us investable and relevant into the future. Running across everything we do is innovation, efficiency, technology-driven approach, and I think it's been a core component of how we've created value in the company. It's a powerful combination. I think it makes us resilient, it makes us sustainable, and it delivers growth. It's those words of resilience, sustainability, and growth that you'll see run through all that we're doing today and we'll pick up through the presentation. I do want to look a little bit back on our track record of delivery, and we've created significant value creation over the period. You can see here, as we bought Edvard Grieg onto production and then Johan Sverdrup, and they reached plateau, and those out-performances that we'll talk about in a moment. We've seen reserve growth and production growth. That's driven us eight times production growth over the last five years, reserve growth. With the quality assets we have, we've seen very low operating costs, industry-leading, and we've reduced carbon emissions. Through all of that, we've added significant value, around $4 billion of shareholder returns over the last 10 years. On top of that, doubling the share price in the same period, so delivering significant value creation. If we now turn to 2020, I think our performance was really good. We delivered very strong set of results that we announced this morning. It has been a challenging year for all. I think everyone will agree with that. The impact of the coronavirus crisis on the world and people's health has been a big issue. Of course, our thoughts go out to those who've been impacted personally by this terrible disease. I do think we're going to see this continue well through this year, maybe beyond. Our team has done a tremendous job to manage the crisis with agility and flexibility and keep everything on track. We've kept all our operations running. We've kept all our projects running. As a result, we delivered strong production last year at the top of guidance, 165,000 barrels a day. We had a really great Q4 with record production, quarterly production of 185,000 barrels a day, which I think sets us up very well as we step into this year. That's now 22 quarters in a row that we've exceeded guidance. We've also continued our trend of industry-leading low costs, $ 2.70 a barrel, again, better than guidance. These two key metrics have been driven by out-performance of our key fields. We announced last year a reserve increase at Edvard Grieg, and we are extending the plateau, and I think we're going to see more there. Johan Sverdrup has continued to outperform with capacity increase significantly through the year. We announced this morning that we'll get to 535,000 barrels a day by the middle of this year. That's 100,000 barrels a day more than originally conceived. That's come for zero cost. We had a good result on resource replacement, over 210% resource replacement, showing we're growing the business. On the back of those strong results, we delivered strong free cash flow generation of $448 million last year, 1.4 times dividend cover. A good financial response, particularly given very low oil prices. Teitur will get into the financials later. I think overall, very strong results in a very challenging business environment and demonstrates the resilience and quality of our business. Now I want to look forward to what to expect, first of all, in 2021. We're guiding production of 170 to 190,000 barrels a day. That's an increase on the long-term production guidance that we provided at the Capital Markets Day a year ago of 160 to 170. Just to reiterate, 170,000 to 190,000 barrels a day this year. We're continuing the trend of sustained low operating costs. $3 a barrel is the guidance. We continue to see out-performance and progress on our key assets. Johan Sverdrup, as I mentioned, we'll see the capacity lift to 535,000 barrels a day middle of the year. It's a big year for Phase 2 as we start the major offshore installations. As Dan will show, that project's still on track. It's also a big year in the Edvard Grieg area, not least of which we have three project startups, which obviously support the plateau longer term, and those are key projects for us to bring in. We have a material growth program, which we're progressing, and I'll come to in a moment. On top of that, we announced this morning acceleration of our decarbonization strategy, I'll get into that with a slide in a moment. On the back of strong performance last year and a strong outlook for the business, the board's recommending a dividend of $1.8 a share. That's an 80% increase over last year. Really just bringing us back to the original proposed dividend, gives a yield of well over 6% and above the majors. Of course, is in line with our policy that we say we can deliver sustainable dividends even below $50 a barrel. It's a big program in 2021, I think it progresses our value and growth agenda ahead. I now want to look beyond 2021 and how we're going to continue to deliver growth. We see multiple growth paths in our business. It's around maximizing the recovery and with step-outs around our world-class assets. It's about continuing to explore in the mature basins in Norway, where we still see plenty of opportunity. It's continuing to have a component of our spend on frontier area exploration where we see higher reward opportunities, but perhaps with higher risk. Complement that with opportunistic acquisitions where we can find opportunities that fit strategically, but also that we can do at a price where we can create shareholder value. We continue to build our position in Norway. We're one of the leading explorers in Norway. We have seven core areas. We expanded our footprint there last year with new licenses, over 20% increase in our acreage footprint, and we now have 3 billion barrels of prospective resource in our portfolio, which we're working to build and bring forward. We're creating a pipeline of opportunities, and I think provides the platform for growing into the future. We're delivering on that growth strategy. First of all, our world-class assets underpin our growth and they continue to outperform. You'll see as Dan and Kristin go through that the facilities and reservoir outperformance that we see, and we have four key projects underway that will come online in the next two years. We're also aiming to sustain production. We have nine potential new projects which we're working to mature, and to take benefit of the tax incentives that make those projects more attractive and to move forward. You'll see more about that today. We're delivering a future growth with a material exploration program, and Per Øyvind will cover that today, but we aim to have a material program going forward. We have that again this year. That in the past has delivered a strong resource addition. If you look over the last five years, we've had 150% resource replacement ratio, which means that for every barrel we've produced in the last five years, we've added one and a half barrels, so growing the business. I'm excited by the opportunities that we have. I really think we've got some great prospects ahead, and I'm confident that we can keep growing the business into the future and adding value. Putting that together, it does deliver long-term growth, and it gets better and better. If you look back over the last few years, we've moved the trajectory here ahead quite significantly. I'll reiterate our guidance this year is 170,000 to 190,000 barrels a day. That's an eight times increase in production since 2015. We're now saying that we can certain of growing to over 200,000 barrels a day by 2023, Dan will show you how we're going to get there. We aim to sustain over 200,000 barrels a day with upsides and new projects. I think we can continue to do that. A lot of what we'll show this afternoon will give you the background to support that. The second element of our strategy is around financial resilience. Our world-class assets, low-cost assets deliver high-margin barrels. You can see that in some of the metrics here. Low free cash flow breakeven, so around $10 a barrel for our 2P investment profile. If we add all of the contingent projects we have in, it only goes to $15, showing that we have a resilient business to downside prices and of course, leveraged on the upside. Of course that quality business delivers strong free cash flow, $4 billion-$6 billion over the period 2021 to 2026 at relatively modest oil prices, giving us the flexibility to balance capital allocation between funding growth, managing conservative debt position, and providing a sustainable and growing dividend. With our resilient asset base, I think we can do all of these things going forward. The third element is delivering on our decarbonization strategy. We announced this morning that we're going to accelerate the plan to become carbon neutral to 2025, with operational emissions, and that's from the previous target of 2030. It's supported by a real plan of activity. First of all, reducing emissions largely through the electrification of our offshore facilities we've been working on over a number of years. But by 2023, over 95% of our production will be powered from shore with electricity. Of course, we're using a lot of energy and we've committed to invest into renewable energy to support that usage. We've done projects so far that cover around 60% of our energy usage, and we've committed to, by 2023, to cover 100% of our usage with our own generated renewable energy. The emissions that we can't then offset, we've committed to some natural carbon capture reforestation projects to offset the balance. When you put that together, it means we can achieve carbon neutrality from 2025, and that's going to be a first for the upstream industry. I see this as good value, good business from many dimensions. Our power offshore projects, our renewable projects, make good returns. The fact that we're doing this attracts and retains investment from investors, and I think likewise for debt financing, it attracts and retains debt financing. We think in time, customers of our barrels will see value in buying barrels that are produced in a low-carbon way. My view is it's not only the right thing to do, it's also good business all around, and it's core to our strategy. Zomo's got a section later which we'll get into and provide more background to what we're doing there. Responsible operations define our license to operate and how we do our business, and our team in Norway put a huge focus on this aspect of our business. We have a strong HSE track record. I think we fell a little behind our usual high standards in 2020 on personal safety, but we still ended up around Norway industry average. We have also continued strong performance in other aspects of safety in our business. I think doing a great job overall. Let's set out our ESG ratings here. I don't propose to go through them, but you can see that on every one of them, we rank in top quartile amongst our peers. I think it shows great justification for what we do and how we do our business. It's an important aspect for how we see and get recognition for that. This is my final slide that summarizes the key message I wish to leave you with. First of all, we're delivering strong growth. You can see a trajectory to go over 200,000 barrels a day by 2023. We have the assets to sustain at that level with upsides and new projects, and we'll show that. I think we have a pipeline of growth opportunities ahead of us that will be able to keep us at that level. Our business is resilient. Long-term OpEx guidance of $3-$4 a barrel, that's industry-leading. We deliver very low free cash flow breakevens, means that we deliver strong free cash flow, $4 billion-$6 billion over the next six years, meaning that we can support a sustainable dividend long-term. We announced yesterday a reiterated $1.80 a share, an 80% increase on last year's dividend. We have the capacity and strength of business to be able to sustain a growing dividend going forward. It's about sustainability. It's about delivering on our decarbonization strategy and becoming carbon neutral in 2025. We have a clear path to get there. Of course, it's about continuing to focus on safe and responsible operations in everything we do. I think it demonstrates that we can deliver both economic growth and environmental benefits, and it makes us resilient and relevant into the future. Those are the key messages I want to leave you with. We'll be picking up those through the day or the afternoon. We'll of course, be happy to come back and answer your questions later. With that, I'd like to now hand over to Daniel, who's going to talk about our producing assets and start to give you a flavor of how we're going to deliver on those targets I've set out. Thank you very much. Thank you, Nick. It's an honor to be here today at an exciting time for Lundin Energy as we have a great platform, as Nick's touched on, to grow from this point forwards. Today, alongside my colleagues in Norway, we're going to spend a little bit more time talking about how the company is going to grow from today to 200,000 barrels a day, how the assets and the projects that we have are going to grow to that level, and then how we're going to sustain that level in the medium term, and also the platform that we have in the exploration side to deliver that 200,000 barrels a day in the long term. I'll spend a little bit more time on our guidance. I'll talk about the assets that we have and the projects that we have and the upsides that we have to grow to 200. Kristin will explore the new projects and the new opportunities we have to sustain that 200 in the medium term, and then Per Øyvind will touch on the exploration program as we move forwards. If we start with our 2020 production, we hit record levels in 2020, both on an annual basis and in a Q4 basis, and that was underpinned primarily by Edvard Grieg and Johan Sverdrup. If we look at the Q4 record production, we had two themes that underpinned that performance. One was the capacity, and one was the uptime on both of those assets. Through the course of Q4 on both Grieg and Sverdrup, we hit nearly 100% uptime on both. On the capacity side, we announced in Q4 that we'd completed capacity testing on Johan Sverdrup, and we lifted the capacity of Johan Sverdrup up to 500,000 barrels of oil per day. We saw that online from the start of December, and that underpinned one element of our outperformance in Q4. If we look at Edvard Grieg, in Q4, we also hit around a 100% uptime. With Ivar Aasen online, they did not meet their contractual capacity, and so we were able to utilize that additional capacity in Q4. So that record production in Q4 was underpinned by those two assets at capacity and uptime. That puts us, as Nick touched on, into 22 quarters running of delivering our guidance, which is a phenomenal record. We're going to spend a little bit more time exploring, in my section, Edvard Grieg, Johan Sverdrup, and the upsides of those assets and how that translates into our guidance and growth. Kristin and Per Øyvind will touch a little bit more on the other assets and opportunities. If we step forward into our production guidance for 2021, as Nick mentioned, we're at 170,000 to 190,000 barrels of oil equivalent per day through the course of 2021. Again, the themes that drove our outperformance in Q4 are driving our production and our range through the course of 2021. On Johan Sverdrup, we will be increasing capacity up to the 535,000 barrels of oil per day that we mentioned before. On Edvard Grieg, we'll be looking to utilize some of the additional capacity that Ivar Aasen is unable to use as we progress through the course of the year. We'll delve into that in a little bit more detail as we get into each of the asset sections. In Q2, we have a big installation campaign ongoing on Johan Sverdrup, and we see a little bit of the impact in our production in Q2. As we move into the second half of the year, we will see both the capacity on both Edvard Grieg and Johan Sverdrup stepping up in the second half, and that drives the performance towards the second half of the year. A resilient business needs to be based on low costs, and so we see another year where we have record low operating costs. We delivered in 2020 $2.69 US per barrel. In 2021, we are guiding that at around $3. Long term, we're bringing down our guidance level from $3.20-$4.20. We're bringing that down now to $3-$4, underpinned by the performance and strength of our assets and the confidence we have in those assets moving forwards. You can see there in 2020, we were significantly lower than the North Sea average, and even at around a third of what we're doing across the Norwegian Continental Shelf. We see that performance going forwards through the future. We're going to spend a little bit more time on each of the key assets we have and the key themes that underpin our business. Johan Sverdrup truly is a world-class asset, and it is in a league of its own. Phase 1 performance continues to exceed expectations, whether that's on capacity, whether it's on reservoir performance, whether it's on environmental footprint. We are exceeding expectations in nearly every single area. In 2020, we reached plateau production on Johan Sverdrup. That was 440,000 as we entered the year, 440,000 barrels of oil per day. We exit the year with almost 100,000 barrels of oil per day more than where we entered the year in terms of capacity. We did that at less than $2 per barrel cost. We did that at less than 0.2 kg of CO2 per barrel emissions. That really is unmatched across the industry. Phase 2 remains on track. We'll start up Phase 2 in Q4 of 2022. The project team have done a really good job navigating the challenges of the COVID pandemic and ensuring that not only our operations continue, but also our project continues to remain on schedule and on cost. Truly, this asset really is in a league of its own. On the capacity testing side, you can see here the ramp-up through the course of 2020 up to the initial plateau, and then the stages of capacity testing we undertook through the course of the year. In November, we tested the oil systems to 535,000 barrels of oil per day, and you see that as the yellow dot in the middle of this chart. From the tail end of the year, we increased capacity to 500,000, and we're awaiting the improvements on the water injection system, which will support the offtake rates at a much higher level. We're expecting to complete those water injection upgrades in the middle of 2021, that will allow us to lift the capacity up to 535,000 towards the tail end of 2021. We have ample well capacity to support these levels. Once that water injection comes on, we have enough today, and we will have enough going forwards, well capacity, to support those increased offtake rates. If we look at the stages of capacity over the course of 2020, we started the year at 440,000, and we've added 100,000 through the course of the year. You see in April, we raised that to 470,000 on the back of the capacity testing. We raised it again on the back of the November, and we announced in November 500,000 barrels of oil per day. We're now announcing 535,000 barrels of oil today, contingent on the water injection capacity increase. For very little cost, we've added almost the size of another major oil field into the business here. That truly is an amazing achievement. Now, you'll notice in Phase 2 that we haven't upgraded the Phase 2 capacity at this stage on the back of the upgrades on Phase 1. Really there's a lot of work ongoing at the moment from Equinor and the partnership to fully understand the system limitations. Today we have the 2 phases of 535,000, Phase 1, and 220,000 on Phase 2, which hasn't been updated since the PDO, adding up to a combined level that's higher than what we're holding here as a full field. Once we understand a little bit more about the common systems, primarily around the export and offtake routes and some of the other common systems driving performance between the two, we will look to address the full field capacity. At this stage, we aren't able to lift that beyond the 720,000 until we complete that work. I see here 100,000 barrels or almost 100,000 barrels of oil increase since first oil, and there is plenty of opportunity beyond that if we're able to debottleneck Phase 2, and also the common facility systems that we have between those two phases. None of that's possible without having a world-class reservoir sitting behind the field. This truly is one giant continuous reservoir with world-class performance. We have excellent continuity over the full structure from the north to the south. We have high porosity, high permeability, all of the ingredients that give us great deliverability per well, and are able to sustain offtake rates of over 700,000 barrels a day once we move into full field production. We're aiming for a recovery factor of in excess of 70%, which is a really strong performance. We're going to know more around how this reservoir performs as we see more production performance. We've installed cutting-edge technology, and we continue to make the most of the technology in front of us to help understand how this field is performing and to give us all of the data we need to fully optimize and increase performance from the asset, whether that's fiber optics and tracers in each of the well bores, which gives us real-time data on exactly what's happening downhole, through to the permanent reservoir monitoring and 4D seismic, which is going to tell us how the reservoir is performing in the fullness of time. With that plus the production experience, we will understand more and more around how this reservoir is performing, and that will unlock the ability to understand what the true resource potential from this field is. We have a drilling campaign that is ongoing. It will continue from the field center and from the Deepsea Atlantic once that comes online in 2022. That drilling program will continue right up to the end of 2024 and even into early 2025. On Phase 2, we're now more than 50% complete. The project really have done an amazing job keeping this on schedule in the midst of a global pandemic, which is impacting lives and livelihoods everywhere across the world. That truly is some achievement. In Q2 of this year, we'll see the main facilities will all then be in Norway, and most of our equipment will be in Norway. The final piece to arrive is the main support framework from Thailand, and that'll come to us in Q2. All of the jacket, the elements for the P2 module, and the riser platform module will all be in Norway. That will start a big program of activity in 2021. The jacket will be installed first, followed quickly by the riser platform module. In behind all of that, we will be ongoing with all of the subsea facilities and subsea equipment, which will be installed through the course of 2021. That should come to an end towards the end of the year, which opens the door for the drilling program to take effect from the start of 2022 onwards. In the spring of 2022, we will see the module or the full topsides for the P2 platform being installed, and power from shore will be online shortly after that point. Then we start the final commissioning offshore between that installation and first oil in the fourth quarter of 2022. This remains on schedule. This remains in line with the cost of the PDO as well, which again, is an amazing achievement by the project team. If we move now to Edvard Grieg, we have an amazing story on Edvard Grieg as well. We're going to talk both about Edvard Grieg and the Edvard Grieg area. Edvard Grieg area, our goal really is to keep the facilities full and to extend plateau, and you're going to see in a slide or two how we've been able to extend plateau so far and the opportunities we have to continue to extend plateau on Edvard Grieg. Both Kristin and Per Øyvind will delve in a little bit more detail into the opportunities we have to support the facilities remaining full on Edvard Grieg. First and foremost, the Edvard Grieg field, that continues to exceed our expectations. We saw last year we had a reserves increase and an extension to the plateau production. We have an infill program in 2021 on Edvard Grieg, and we have potential for additional capacity on Edvard Grieg due to the Ivar Aasen declines. Power from shore will also be online from the end of 2022. If we look then at the future activities, Kristin's going to go in a bit more detail on our tieback projects, and they'll be online in Q3. We have in Per Øyvind's section, we have a little bit more of the exploration and appraisal activity that we're going to be doing in this area, which ultimately the aim is to grow the resource base, extend the plateau, and add in barrels to existing infrastructure, which are by far the most valuable barrels that we have. It doesn't stop there. We've been in the Utsira High for many years, that will continue into the future, we're still finding opportunities to grow the business in this area. Edvard Grieg really is a world-class asset. Whether it's low operating cost, high efficiency, low CO2 emissions, this asset is really performing. We delivered last year with less than $3.50 per barrel operating costs. We delivered high efficiency, greater than 95% through the course of last year, we're guiding this year at 96%. We did it with low emissions, less than five kilograms of CO2 per barrel, a quarter of the industry average, we will be moving down to around 1/20 of the industry average once we get into power from shore from the end of 2022 onwards. That doesn't come by chance. Our team in Norway are doing an amazing job to understand, optimize, and improve efficiency on this asset, whether it's deploying the latest technology, understanding the data from all of the sources that we have around the field and around the reservoir, or using machine learning and cutting-edge technology on pattern recognition to understand how our assets are performing and to give us opportunities to go and optimize beyond that. As we look forward, today we have a contractual capacity on Edvard Grieg of around 95,000 barrels of oil equivalent per day. You see through the course of the year, we were roughly at that capacity. We've seen some increased capacity in Q4, and through the course of 2021, we will see that capacity improve further as Ivar Aasen starts to come off plateau production. Ultimately, we can increase our capacity on Edvard Grieg up to 135,000 barrels of oil equivalent, depending on how much of the available capacity is used by Ivar Aasen. With the team we have in place, with the asset we have in place, we will continue to deliver good performance on Edvard Grieg, I'm sure of that. As we move into the future, we're only going to get stronger and stronger on the Edvard Grieg asset. Again, supported by a really strong reservoir. If we look back to when we sanctioned this field back in 2012, we had a PDO level of 186 million barrels of oil equivalent. Today, we're sitting at almost double that at 350. That's been driven by a range of elements. One, there is more oil in place in the field. We've explored, whether it's the five wells that we've drilled since the PDO, we've found upsides through those wells. Whether it's the new wells that we're putting in and some of the new technology, so Fishbones completions are going into this next infill campaign, which improves the reservoir contact and improves the ultimate recovery of each of those wells. Whether it's the infill program we have this year. That's going to add on its own, is going to add around 18 million barrels of oil equivalent, which is already in the P2 resource base. There's an appraisal element to that infill program as well. In the Jorvik Basin, we've discovered it through the E&A well that we had in the northwest of the Jorvik Basin. Both of these wells will test upsides in the Jorvik Basin for one of the branches of A- 16, and it will test the Jorvik High, which is sitting on our prospective resource base at the moment. The well in the southwest of the field will test that southwestern flank and the extension of Edvard Grieg down there. If we find better reservoir quality, better facies distribution in the southwest or a deeper oil water contact, we may see upsides from that region. This field continues to grow and continues to develop. Beyond the 2P reserves, we still see opportunity to further grow this field on the back of the success from this year's campaign. Keeping the facilities full really relies on the full Edvard Grieg area delivering into that piece. To date, it's been the Edvard Grieg field and some of the near-field 2P projects that we've brought on, or that we will bring online in Solveig and Rolvsnes. That will come online in the course of 2021, and that has already extended our plateau, as you'll see in the coming slide. When we step beyond that, we have upsides from all of those projects, whether it's the infill drilling in Grieg unlocking some upside, whether it's full field development of Rolvsnes and Solveig, or whether it's into the exploration campaign on Lille Prinsen and Segment D and Merckx. We have plenty of opportunity to continue to grow the resource base in this area. This is a real key focus for us. We're drilling nine wells this year. We're spending over 50% of our CapEx budget, and we're aiming to mature around 220 million barrels of reserves, resources, and prospective resource into the mix here. Today, we're sitting on a region with 400 million barrels of 2P reserves, and we have the opportunity on success to double that to around 800 million barrels of resource and reserves eventually. This area will be and continues to be a key focus area for Lundin Energy as we move forward. All of that comes together in the production chart, which is ultimately what we want to see here. From PDO to today, we've managed to extend the field plateau by over five years. At the moment, we see that plateau extension to the end of 2023, which includes the Edvard Grieg field, Solveig, and Rolvsnes. If we are able to unlock some of the 3P reserves, some of the increased capacity, and some of the prospective resource that we are chasing at the moment, on top of the projects that Kristin will touch on in the full fields, we can see not only capacity increasing on Grieg, but that plateau extending further. So as we sit here today, we have produced already almost all of what we had in the PDO back in 2012, and we have the ability to produce more than that going forwards, and it remains a key area that we will focus on in the future. In the Alvheim area, onto the third producing asset that we have, it is a very similar story to Edvard Grieg. This is an asset that has continually added resource and reserves into the mix and continually extended the production from the field. Kristin will touch on this in a bit more detail on the future projects, but we have not only 2P upsides, we have 3P upsides, we have infill activities, and we have new projects plus exploration that can continue to keep Alvheim growing in the future and can continue to add to the resource base. That sums up the key assets that we have. I have a few slides here which talks to the resource position, then I'll bring that all together into the growth elements for the company. Here you see the overview of the resources, the reserves, and 2C resources. I want to draw your line to the replacement, which we're going to touch on a little bit more in the next slide. We have revisions to the 2P, so increases to the 2P, which is primarily the Edvard Grieg increase through the course of 2020. In the 2C resources, we have two elements driving the increases in 2C. One of those is the acquisition in the Barents Sea, and the second is the discovery of Iving. If we put all of that together, that adds up to a 210% resource replacement ratio. That really is the core of what we're trying to do here. We need to be adding resources into the base, maturing those to 2P reserves, and adding that into the production mix. If you look back over the last five years on both resources and reserves, we've seen resource and reserves growth more than the production on average for that period of time. Our goal is to continue to do that. We'll see more in Kristin Færøvik's section, where we discuss a bit more around the activity sets that we have to continue to grow this resource base. This puts me to the end of my section with possibly my favorite slide from the presentation, which shows the growth that we have in the company. As I've touched on today, we see 2P reserves growing from today to over 200,000 barrels of oil equivalent per day by 2023. If you just look at what we had at the end of last year, which is what we showed the end of, sorry, 2019, which is what we showed you last year at the Capital Markets Day, that's the red line on this chart. In the course of one year, we've lifted that line to where the solid blue bars sit at the bottom of the chart. That's quite an amazing achievement. That's an extension of the plateau on Edvard Grieg, also the addition of the capacity on both Johan Sverdrup and Edvard Grieg. If we move into the next tranche on this, the lighter blue bar, that really is unlocking the 3P that we've touched on on Edvard Grieg and Johan Sverdrup. If we're able to unlock the 3P, we remain above that 200,000 without any further investment or without any further activity. If we look at the potential projects, which is a nice segue into the next section, which Kristin's going to pick up, we're going to talk about the projects that we have that sustain 200,000 barrels per day in the medium to long term. Without further ado, I'll pass you over to Kristin Færøvik in Norway, who's going to take us through the upsides and projects. Thank you, Daniel, and a very good afternoon to you all. I'm delighted to be able to talk to you today about the portfolio of projects supporting our ambition to sustain production at 200,000 barrels of oil per day over time. Four projects are in the execution phase and are well underway to deliver new barrels. In addition, we are working very hard to mature a potential of nine new projects that can add up to 30,000 barrels of equity production from 2025, collectively representing a resource potential of 200 million barrels of oil equivalents net to Lundin Energy. What these new potential projects have in common is that robustness was significantly improved by the temporary tax changes approved by the Norwegian Parliament last summer. In an effort to combat an oil price and pandemic-driven slump in activity, Parliament provided the industry with strong incentives to mature projects and continue investing through to the end of 2022. I think it's fair to say that the industry is delivering on these expectations. With a break-even reduction of about $10 a barrel and a significant increase in the internal rate of return, we quickly identified a number of projects and opportunities for value creation that we have diligently pursued since the middle of last year. On this note, I'd really like to commend our business development team, as a great many of the opportunities have been supported and facilitated by creative, value-accretive, and fast-paced transactions. Let's start with a quick overview of both ongoing and future projects. I will review many of them in more detail later on, the four projects in the execution phase are Johan Sverdrup Phase 2, Daniel have just given you an update, I won't dwell on that any further. We have the two tieback projects to Edvard Grieg, Solveig Phase 1, and the extended well test on Rolvsnes. Fourth, we have the infill program at Edvard Grieg, where the Rowan Viking jackup rig parked next to the production platform earlier this year, embarking on a program of three infill wells. There are three projects moving firmly towards sanction before year-end 2022. They are the two subsea tiebacks to Alvheim FPSO, of course, our newly acquired asset in the Barents Sea, the Wisting project. Last but not least, we have six potential projects that we seek to de-risk during this year in order to meet the end 2022 deadline. These are all in familiar territory to Lundin. In the south, i.e. in the North Sea, our projects are clustered around existing infrastructure that we have or are already invested in, and for the most part are operator of. A Solveig Phase 2 is dependent upon production experience from Solveig Phase 1. Segment D could be a bolt-on project that, provided we have success in the exploration well to be drilled in 1Q this year, could be developed together with Solveig Phase 2. Full field development of Rolvsnes is dependent upon production experience from the extended well test. Partner-operated Iving requires an appraisal well this year in order to move forward with the development. On the Loppa High, we have the Alta discovery, where feasibility studies are being conducted. Finally, the Lille Prinsen discovery will be appraised also this year. I'll start in the north when I tell you a bit more about each of these projects. Significant resources have already been discovered in the Barents Sea. About 3 billion barrels of commercial resources have been or are in the process of being commercialized. Our next speaker, Per Øyvind Seljebotn, will talk to the yet to find potential of the Barents. Lundin Energy is very pleased to have acquired a stake in a high-quality asset in the area, and one that is also moving towards sanction within the end of 2022. Wisting reserves are in the order of half a billion barrels, so it's a very significant project. With Wisting entry, we have equity in a strategic asset that will see the development of a multi-lobe reservoir with very good lateral continuity. Last but not least, we will get entry to new infrastructure in this still relatively undeveloped part of the Norwegian Continental Shelf. This year is indeed a very exciting year to enter the project, as many key decisions shaping the development of Wisting will be made during the course of this year. The project will move through concept select later in 2021, followed by the development of a plan for development and operation for submission to the Norwegian Parliament by the end of 2022. We are particularly encouraged that options are being pursued to fully electrify the facility with power from shore. I very much look forward to support and challenge the operator in the decision-making going forward. As we have informed you in the past, the Alta resource base does not justify a standalone development with a new-built facility. The extended well test performed during 2018 proved good productivity, and the discovery will be monetized in due course. Our base case has, for the last year, been a subsea tieback to Castberg for whenever the capacity opens up on the Castberg facility. The temporary tax changes gave us an incentive to instigate a few focused feasibility studies, and the conclusion of these will be drawn in the first half of this year. In the Alvheim area, we have a couple of projects coming for sanction this year already. The Kobra East Gekko, or KEG for short, as we say, field development project targets two separate discoveries, Kobra East and Gekko, both located within the Alvheim production license. The development is planned as a subsea tieback to the Alvheim FPSO through the Kneler B manifold that's already installed on the seabed. The reservoir in the Gekko discovery, which was made as far back as 1974, is Heimdal formation turbidites and similar to Alvheim. Kobra East is Hermod injectite sand, which is analogous to Kobra and Volund. Kobra East was discovered in 2016 as a prolongation of the Kobra production well. I think it's fair to say that this project is a testament to the drilling capabilities built over years of Alvheim experience. Based on the track record of several Alvheim infill wells, confidence has been gained in the ability not just to place these wells, but more importantly, in producing from thin oil columns. In addition, the operator has extensive experience of drilling multilateral wells, which also forms the basis of this project. Sanction of KEG, i.e. submission of a plan for development and operation, is expected in the middle of 2021. The second project in the Alvheim area due for sanction this year is the development of the Frosk discovery, in which we've had a test producer since August 2019. We understand this to be a well-connected, complex injectite reservoir geometry, but with excellent porosity and permeability. In fact, the Frosk test well has produced slightly better than expected. This development will also be a simple subsea solution tieback to Alvheim through the existing Bøyla manifold on this occasion. In addition to the already drilled and completed production well, two more wells will penetrate the Frosk reservoir. PDO submission is expected in 3Q of 2021. Debottlenecking and lifetime extension of the Alvheim facility are constantly on the agenda in the license, ensuring that the area potential is exploited to the full. Hence, I am confident the value creation from this area will continue. If we then move further south, Lundin was party to an exciting discovery made last year called Iving. The main reservoir intervals are in Skagerrak and lower Statfjord formations, and both reservoirs will be tested by the appraisal well planned for later this year. We also expect to be production testing in the Skagerrak formation. Most likely development solution for this discovery is a subsea tieback to existing infrastructure. Balder is the closest, some 10 km away, but Ivar Aasen and Edvard Grieg are also host candidates. The partnership is fully aligned on the effort to mature this project within the 2022 deadline. Now we have moved well and truly into the heartland of Lundin, where we have worked systematically over years to explore and exploit the subsurface to maximize recovery and maximizing the value of the infrastructure investments that have been made through the development of the Edvard Grieg field. While we've always taken great pride in maintaining pace, there is no doubt that the heat is on for most of the organization, should we have the success we hope for in maturing new projects for sanction next year. This is a challenge we are all extremely excited about. This picture gives an overview of all that is happening in the area in 2021. In the following, I'll go through them in more detail. While I'm still on this picture, I'd like to point out Lille Prinsen, located some eight and a half km northeast of Ivar Aasen and some 15 km from Edvard Grieg. We have recently increased our equity and agreed transfer of operatorship from Equinor, subject to authority approvals, of course. Earlier this week, you may have seen us signing up additional rig capacity, which will be used to drill the appraisal well that is required to prove up whether we have a commercially viable project in this discovery. We plan to test both Zechstein, which is a carbonate reservoir, and Heimdal, which is turbidite sand reservoir, with the appraisal wellbore. Very exciting well coming up. Our projects in execution in this area are Solveig Phase 1 and Rolvsnes East extended well test. The project team, together with our main contractors, TechnipFMC and Rosenberg Worley, in addition to our operations team, of course, has done a phenomenal job to keeping the project on track during a year of unprecedented challenges. With down and up manning offshore, with deliverables from all over the world, with quarantines and travel restrictions, I'm just very impressed with how these challenges have been overcome, and very pleased to see continued strong collaboration with our contractors and suppliers. The subsea campaign for these projects was successfully executed last year. Topsides modifications on Edvard Grieg are going really well, and Solveig development drilling will start in the near future with a semi-submersible West Bollsta. We are well on track for first oil for both projects in third quarter of 2021. The icing on the cake is the project economics are even more attractive now than at sanction due to the temporary tax change which applies to all capital investments prior to year-end 2022. Production and reservoir behavior from Solveig and Rolvsnes East is going to be exciting to follow, and not just because of the revenue stream they provide, but also because that information is crucial to determine the next steps of development for the area. A second phase of Solveig is dependent upon production experience from Solveig Phase 1. The Solveig reservoir consists of alluvial to eolian sediments of very good quality, and a phase one producer will be extended into the phase two area to appraise the reservoir quality and producibility of the syn-rift formation. Segment D could be a bolt-on project to Solveig Phase 2, provided we have success in the exploration well to be drilled in the first quarter of this year. A full field development of Rolvsnes will be de-risked through production experience from the extended well test. Fractured and weathered basement make up the reservoir in Rolvsnes, which flowed 7,000 barrels of oil per day at a constrained choke during the 2018 drill stem test. The extended well test will test water cut development and contribution from porous weathered basement. If we gain confidence in the recovery factor, the development scheme will be further wells to be drilled into to tap the reservoir potential, but using the infrastructure that we've already put in place with the pipeline to Edvard Grieg and processing, and the modifications made to the top sides to provide for the processing of both Rolvsnes and Solveig. In summary, we have a very exciting program for 2021 and many potential projects to mature that will add materially to sustaining our production ambition of 200,000 barrels per day. With our fit-for-purpose execution model, our long-standing relationship with suppliers and contractors, and with a strong team of people, we are well equipped to take on that challenge. It all starts with reducing the uncertainty of the key input to our decision making, and the factor that has the most impact on project economics beyond oil price, that is. Namely, getting to grips with what lies in the subsurface. High quality resource definitions and drainage strategies are critical to maximize value creation from any oil and gas project. On that note, I have the pleasure of handing over to our exploration and reservoir development director, Per Øyvind Seljebotn. Good afternoon, everyone. I will now talk you through a section on organic resource growth with the title Delivering Future Value. We will talk about our overall exploration strategy and our 2021 exploration and appraisal program. The key takeaways from this section should be that we have an exciting 2021 E&A program. The program is balanced between high-value near field opportunities and frontier high impact exploration. This balance can also be seen in our exploration strategy, where we are continuing to expand our portfolio into the more mature but still highly prolific areas of the NCS. Our main core area is still the Utsira High, and this is where we're spending most of our E&A dollars this year. Let's start with this overview slide. We are continuing to build on our exploration strategy. Just a few years ago, we were mostly focused on the Utsira Alvheim and the Barents Sea. We are now continuing to build seven core areas across the NCS, where we are focusing on our exploration efforts. From 2017, we have doubled the number of licenses we have on the NCS, and we now have more than 100 licenses. We continued this journey by being awarded 19 exploration licenses, including seven operatorships in the APA 2020, the biggest award that Lundin has ever received. We believe that very profitable opportunities exist on the NCS, both the possibility of making large discoveries in a frontier setting and making high-value discoveries near infrastructure. The NPD estimates the yet to find to more than 15 billion barrels on the NCS. In 2020, a little bit more than half a billion barrels were discovered on the NCS with the technical chance of success of around 45%, which is quite good. Our exploration portfolio contains around 3 billion barrels of net unrisked prospective resources, of which we are targeting around 300 million barrels this year. For the future, we are building exploration programs and targeting to drill about eight to 10 exploration appraisal wells each year. Our overall finding cost still stands at about $ 0.80 a barrel. Now I'll spend some time to talk about technology and capability. First and foremost, we have an excellent subsurface team, and this team has delivered discoveries that Lundin Energy is built on, the Edvard Grieg and Johan Sverdrup discoveries. It is this team that, together with the rest of the organization, has delivered 150% resource replacement ratio over the last five years. We also take pride in that we successfully have developed reservoirs that are new to the NCS, and that we have been unlocking new plays on the NCS. We continue and want to be doing more of that into the future. We have built an in-house expertise on all the key areas that helps us evaluate our exploration targets and the subsurface on our fields. Adapting and developing new subsurface technology is continuously happening in Lundin. We are considering ourselves as frontrunners in seismic imaging and have been part of the major developments on seismic imaging for the last years. Example here on the slide is the improved image we have on the Edvard Grieg reservoir. If you're not used to looking at seismic, you'll have to take my word for that the lowest image here from 2021 is superior to the other ones. Edvard Grieg was hardly visible on seismic at the time of discovery. As you saw in Daniel's presentation, we are now able to track water replacing oil accurately across the field. This helps us significantly define the reserves in the field, and it helps us significantly on making accurate production prognosis for the remainder of the field life of Edvard Grieg. It also helps us de-risk the infill programs that we are generating on Edvard Grieg, and it helps us identify new infill targets for the coming infill programs on Edvard Grieg. For the seismic, it's also going to be a key technology for monitoring the reservoir on Johan Sverdrup. We have several in-house projects and are supporting R&D on improved seismic imaging and on bringing down cost and time for processing. Increased computer power, artificial intelligence, machine learning technology enables us to realize projects on automatic seismic interpretation processing that we could not do before and will make us more efficient explorers. On Edvard Grieg, in our three coming infill wells, fiber optics will be installed in the wells. The potential for this technology is huge, both in terms of monitoring well integrity and equipment in the wells, but also to gather seismic around the wells and help us understand how to optimize production both in short and long term. We definitely have high expectation for this technology. We will install Fishbone completion technology on two infill wells on Edvard Grieg. This allows for many small holes to be drilled out on a main bore, up to 12 meters into the formation. It will increase reservoir exposure and improve flow to the wells. This technology alone has been estimated to increase reserves about one to two million barrels on the infill program. We've been following that technology from the very start and are expecting high value back from these installations. All of the technology and experience we gain on these fields and on processing seismic, whether it's on Edvard Grieg or on our exploration targets, we take that learning into the rest of the portfolio. Onto our platform for future growth. Combined resource base of probable, possible, and contingent resources are well above one billion barrels. Daniel and Kristin has talked about how we are working to realize the 3 P potential and mature the contingent resources into reserves and production through the projects. In our exploration portfolio, we have around 3 billion barrels of unrisked prospective resources, and we are constantly working to mature the prospects into drillable targets. We clearly seek to deliver exploration appraisal programs that have a good balance between high-value barrels near infrastructure, targets in mature basins, and high-impact prospects in more frontier settings. We see opportunities to create value in these categories across the NCS. We'll now talk about each of the areas. For Lundin, Utsira High and Alvheim are still our main core area, and six out of seven of our E&A wells in 2021 will be drilled in these areas. It is a very attractive and very prolific area, and we continue to generate opportunities here after already being active here for 20 years, which is amazing. Last year, we participated in three wells in the area, which resulted in the Iving discovery and a small technical discovery on the Enniberg, west of Iving. Our plans for Iving was covered in Kristin's section, and the Enniberg area we are evaluating for more potential in light of the well results. This year, we'll be drilling three wells within tieback distance to our Edvard Grieg facility. The Segment D is potentially high-value barrels in undrilled segment west on Solveig. Our development can take advantage of Solveig infrastructure and potentially be developed together with a potential Solveig Phase 2. Merckx has a higher volume potential immediately south of Solveig, targeting two different reservoir levels. 8.5 km north of Ivar Aasen, Kristin talked about Lille Prinsen, where we're chasing an oil leg between an already discovered gas column in the Heimdal formation. All of these potentially very attractive and very highly valuable projects if we are successful. Dovregubben, in the east of the Sele High, has standalone potential, around 200 million barrels in an underexplored area, with the charge as being the main risk. We see significant upside in this area should we be successful, and we secured more acreage around this license to protect the follow-on potential if we're successful on Dovregubben. We're also participating in a prospect called Lyderhorn south of Alvheim. In this area, we were awarded six new licenses in the APA 2020, which forms the basis for future growth. Now on to the northern North Sea. In 2018, we made a major seismic investment in this area, and we have been efficiently building our presence since then. We now have 13 licenses in this area. The area is highly prolific, and recent discoveries like Dugong, Atlantis, and Echino shows that there is more to chase in this area. We were awarded three licenses in APA 2020 with a well commitment on the prospect north of Veslefrikk. We are aiming at drilling exploration wells in this area next year. On to the Norwegian Sea. In this area, we will not be drilling wells in 2021, but we have two wells lined up for 2022, the Lundin-operated Melstein well that has been delayed from last year, and the ConocoPhillips-operated Bounty well. Both these wells in the Frøya High area, where we've been active for a while. On the Nordland Ridge, we were awarded a very large license together with Equinor and Wintershall. The 2019 Toutatis well proved a working hydrocarbon system in this area, and we're chasing follow-up potential to this. We were awarded a very large license west in the Vøring Basin. This license is in a frontier area with little or no well control and will require reprocessing of seismic and significant work to de-risk before a drill or drop decision can be made. In the large license to the southwest, we acquired a large 3D survey last year, and this license also has large potential but requires significant work on de-risking before a drill or drop decision can be made. On the Halten Terrace, Lundin has not been present. We've now taken a step to change this with a significant seismic purchase from PGS late last year. With the new data, we will be able to assess this area properly, and we'll consider building a presence, much like we've done in the northern North Sea. This area has been proving to be very prolific and are still being made very material discoveries here over the last couple of years. On to the Barents Sea. It's been a very active year in the Barents Sea, and to start in the north, Kristin covered Wisting, a very strategic and material acquisition for us. It gives us ownership and infrastructure in a new area, and we're already well-positioned with exploration licenses in tieback distance to Wisting. The Shenzhou well is scheduled to spud in April and will be drilled in an underexplored area with significant follow-up potential should we be successful. We're also very pleased to have stepped into a nearfield opportunity together with Vår near Goliat. We expect to be drilling the Lupa next year. This is about 25 km away from the Goliat field. No question, we were hoping for another result of both Bask and Polmak on the Loppa High. The results from these wells is obviously degrading our exploration potential on the Loppa High. Barents Sea is still a very large area. It's underexplored, already have three billion barrels of commercial resources, and a significant Yet To Find estimated to seven billion barrels by the NPD. On the longer term, we have secured a license of 4,700 sq km in the Nordkapp Basin. This is a basin with proven oil and a proven working hydrocarbon system. It has reservoirs at multiple levels, but the challenge has been to image the traps in this area. This year, we'll be acquiring a 3,600 sq km seismic survey over this acreage with TopSeis technology. We see potential for standalone discoveries in this basin, but it will require quite a bit of work to de-risk the play and define the traps properly. It's more a long-term game. To summarize, we have seven wells remaining for 2021. The program is focused around Utsira and Alvheim area. It is a mix of appraisal, nearfield exploration like Iving, Lille Prinsen, and Segment D, targeting potential high-value barrels near infrastructure. Merckx has a significant potential and is a prospect in a mature basin just south of Solveig. Shenzhou and Dovregubben, frontier exploration with significant potential, naturally higher risk. To conclude this section, we have our exciting 2021 E&A program that shows a balance between high-value near-field opportunities and frontier high-impact exploration. This balance can also be seen in our exploration strategy, where we are continuing to expand our portfolio into the more mature but still highly prolific areas of the NCS. We are explorers by nature, we are continuously chasing growth, whether it's on or near our existing fields, or it's big potential in frontier settings. Our average resource replacement ratio has been around 150% over the last five years. That was my last slide. I believe we're now up for a 15-minute coffee break, which should take us to around 3:35 P.M. Don't go too far away from the screen. We will also be premiering a corporate film that has been put together by the team. When we see you back in 15 minutes, Zomo Fisher will be presenting our decarbonization strategy. Thank you very much. [Presentation] Welcome back. Good morning and good afternoon to you, wherever you may be in the world today. We hope that you enjoyed the video, which I think gives us a really good segue into the section that I'm going to present to you today, which I'm very excited to do so, on how Lundin Energy is accelerating our decarbonization strategy. Before we begin, I just want to touch again on a few of the key messages that Nick mentioned at the beginning of the presentation today as to the wider context and why we are decarbonizing, and the purpose of our decarbonization strategy. The world today emits about 50 billion tons of CO2 per year, and if we are to meet a target of sticking to less than two degrees in the future, this needs to be halved by over 50%. The production of oil and gas is significant in terms of its contribution to global emissions. It's not just down to us. It's every sector that needs to decarbonize significantly if we are to stick to a less than two degree future. Given that oil and gas is going to be responsible for 45%, at least, of the energy mix in 2040, it is important that we, as a low carbon efficient, responsible, and safe operator, we believe that our role in the energy transition is to deliver the oil that the world needs, this critical resource for nine billion people, in a way that is at very low carbon emissions, safely and responsibly, while returning value to shareholders at the same time. That is the purpose of our decarbonization strategy. We are very excited to announce today that we will become the first oil and gas company to be carbon neutral from 2025 across our operations. Action on climate change is well overdue. We have made significant progress on our decarbonization strategy to date. There is more value on the table to be captured, which is why we have moved forward our decarbonization strategy by five years from the previous goal of 2030 to 2025 today. To deliver this goal, we are going to invest $750 million in electrification, renewable energy generation, and in natural carbon capture, of which 55% of this $750 million has been spent to date. As a business, our primary focus is to decarbonize first, to reduce our absolute emissions, and to cut our CO2 intensity to less than two kilograms of CO2 per barrel by 2023. To achieve this, we're doing a few key things. Over 95% of our production will be electrified by the end of 2022, helping us to avoid 80% of our emissions from our assets. We are also on track to replace 100% of the net electricity consumption that we have from shore with net new renewable power generation by the end of 2023. Our carbon neutral goal also includes our supply chain emissions, and this year we made a commitment to ensure that all of the supply vessels on fixed term contracts to Lundin Energy will be installed with battery hybridization. As a result, today we have the cleanest fleet on the Norwegian continental shelf. After we've done all this, for the hard to abate residual emissions that we still have, we are investing in natural carbon capture projects with tree planting already underway in northern Spain, and I'll touch on that again shortly. In 2019, our carbon intensity was already 3 times better than the world average. Last year in 2020, it was 6 times better than the world average. We measure our carbon intensity on a net equity basis across our operated assets, but also our non-operated assets. We include emissions from drilling in the carbon intensity metric. We already have one of the lowest, if not the lowest carbon intensities in our sector, but we want to go further. After the completion of electrification of Edvard Grieg, and when our renewable energy projects come online, we forecast that our carbon intensity will be greater than 10 times better than the world average. As the video showed, if all the oil in the world was produced in this way, we would save the emissions of equivalent to taking 700 million cars off the road. We are also the first company in the world to be certified with Intertek's new CarbonClear certification. The first company to have their carbon intensity verified for a particular field. Last year, Edvard Grieg was awarded the certification by Intertek, called CarbonClear, which demonstrates that for every barrel of oil we produce at the field, the emissions saved are greater than 80% when compared to an average barrel. We feel that certification of low-carbon barrels is a logical next step for energy companies like us in the energy transition. It helps differentiate barrels on the market that are produced in an environmentally responsible manner, and it creates distinction for buyers. Like with other certified commodities, such as low carbon aluminum, we see the world moving in this direction. For buyers like refiners, certified barrels not only give the full value chain, traceability of the provenance of oil, but it also helps them to enable them to reduce their full lifecycle footprint of the hydrocarbon products that they produce. For products like plastic, construction material, aviation fuels, using low carbon certified feedstocks will significantly reduce the production of these products. This is important because over 60% of the emissions from the production of these products lie in the upstream space. We believe that certified barrels will thus start to command a premium in the market as demand for low carbon products continues to grow. As part of our decarbonization strategy, as mentioned before, we are aiming to replace 100% of the net electricity usage that we have from power from shore with net new renewable generation from new assets. These projects help us in a few ways. They help us to decarbonize our electricity consumption to help us reach our carbon neutral target, but they also generate good leverage returns on their own and provide us with a natural hedge against the electricity price that we have. This is important because once we have electrified Edvard Grieg and Johan Sverdrup Phase 2 comes online, we will be a significant user of electricity in the Nord Pool grid, using about 500 GWh per year. We are on track with the target. Phase 1 of the Leikanger hydropower project that we have in Norway has been completed, and we have a 50% stake in this project. In 2020, about 30% of the net electricity consumption that we had was replaced with renewable energy generated by the Leikanger hydropower plant. Phase 2 of the project should be completed at the end of this year. These 2 projects combined will replace about 60% of our net electricity usage from power from shore. We are currently in discussions on another project that will help us close this gap and meet our target of 100% replacement by the end of 2023. The impact will be significant. In two years' time, we will be generating renewable electricity equivalent to the usage of 130,000 homes. In order for us to neutralize our residual operational emissions that are hard to abate, this year we have announced that we are going to start investing in developing proprietary natural carbon capture projects with our partner, Land Life Company. With an investment of approximately $35 million, we will start planting 8 million trees over 11,000 hectares of degraded land over the next five years. We will start in northern Spain, in the Castilla y León province, and move over to other regions as time progresses. The size of lands that we will regenerate and reforest will be equivalent to a size of land that is twice the size of Manhattan. In addition to capturing 2.6 million tons of CO2 from the reforestation projects, they will attract a range of additional benefits, such as improving air quality, restoring biodiversity, creating local jobs, and injecting millions of USD into the local economy. We are taking this step because, as with every component of our decarbonization strategy, we want to achieve carbon neutrality in a credible and authentic manner that drives real value. We could simply purchase all these offsets from the market at a low cost. As a strategy, developing our own proprietary projects makes more economic sense, delivers higher quality, and gives us flexibility. We are essentially locking in large volumes of high-quality future carbon capture at a relatively low cost per ton of CO2, and this will help us hedge against the price of future offsets. We believe that offset costs are going to increase significantly in the coming years, especially given the huge interest and demand for offsets as a result of many net zero and carbon neutral commitments from our peers and others in other sectors. For Lundin Energy decarbonization, the journey has been and will continue to deliver value, significant value for us, for our shareholders, and wider society. It's part of our DNA, and it just makes common business sense. The examples that you see here are just a few amongst many of the value that is created from our decarbonization strategy. For example, by electrifying Edvard Grieg and Johan Sverdrup, we will avoid $1.4 billion in costs net to Lundin over the remaining 2P reserves from carbon taxes and EU carbon allowances. That is equivalent to avoiding 80% of the emissions from these assets. This takes into account the recent proposal by the Norwegian government to increase CO2 taxes in Norway to nearly $240 per ton by 2030. We will also realize around $600 million in cumulative additional gas sales, as this gas will no longer be required for power production on our platform. As mentioned before, our renewable electricity investments help to reduce our risk by providing a natural hedge and reducing our exposure to electricity price volatility. Furthermore, all of our decarbonization projects, including the investment in reforestation, have had significant wider societal impacts, creating jobs and supporting local economies. Our efforts mean that year on year we have been rewarded by the ESG rating agencies with top quartile ratings. For example, we received an A- on the CDP this year, and we've maintained a double A on MSCI. Thank you for listening. With that note on value creation, I will hand over to Teitur Poulsen, our CFO, to take us through some numbers. Thank you. Okay. Thank you for that, Zomo, and good afternoon, everybody. We are now going into the financial section of the presentation. This is the last section before handing back to Nick for some concluding remarks and opening up for Q&A. The financials really will be centered on three themes, the Q4 and 2020 full year results. We'll go through the key highlights on that. Then we will go through our usual 2021 guidance based on the approved budget we have for this year. Then we'll also look more into the medium term on the cash generation capacity within the portfolio and the improvements that you've heard about from the portfolio, and what the financial frame looks like sitting around that cash generation capacity. Starting off here, looking at the Q4 and full year highlights. As has been mentioned a few times during the presentation, Q4 was a record quarter of production for the company. On top of that, we were actually overlifted by 2,000 barrels, so we sold 187,000 barrels per day for the quarter. We also had very good price realization of $44.70 for the oil, which is actually above the Dated Brent average for that period. Gas and NGL prices have also recovered markedly as we've gone through the back end of last year. Costs are very much still in control, and we continue to report industry-leading low operating costs, $2.40 per BOE for the quarter. The investment levels we had totaled around about the $340 million on oil and gas CapEx and E&A. We also completed the Wisting acquisition in the fourth quarter where we paid $125 million for that acquisition to Idemitsu. For the full year, you see in the top right here, very good EBITDA generation, $ 2.1 billion, which is a record for the company, and also a strong CFFO at over $1.5 billion. One of the key highlights in Q4 is also that we refinanced our credit lines. We moved from an RBL-type structure into a corporate facility. We've now secured funding for the next five years out with $5 billion of credit lines. We exited 2020 with $3.9 billion in net debt, leaving us a current liquidity headroom of $1.1 billion. Some of the key ratios coming out of 2020, we covered dividends by 1.5x in terms of free cash flow generation. We exited net debt EBITDA at 1.8 x on that particular metric. Going into Q4 in a bit more detail, EBITDA generation, very strong, $708 million for the quarter. That's a record for the company. As you can see in the top right, that's driven by very high sales volume, 17.2 million barrels of BOE sold during the quarter. We are up 2% on the previous period last year. CFFO was also strong, $280 million. That was somewhat impacted by a large cash tax settlement we paid in Q4 of $260 million, which related to the 2019 tax bill. Now 2019 taxes bill has been fully settled. In total, during Q4, we paid close to $340 million of cash taxes, and we also had a working capital build of $31 million. That's what led to this 30% decline on CFFO. We have been running on free cash flow quarter on quarter, positive free cash flow for 13 quarters running. This quarter we had a negative free cash flow of $100 million, and that was really driven, again, by this Wisting payment. If you strip out the inorganic element of the portfolio, we were again generating free cash flow in the quarter. Including Wisting, $100 million negative free cash flow in the quarter. Adjusted net results, $87 million. We had an FX gain, which we pre-announced of $256 million in the quarter. Because we refinanced and we expensed the unamortized arrangement fees relating to the original RBL we entered into back in 2016. That was fully expensed in the quarter. Also the loan modification gain we booked in 2018 when we improved the terms on the RBL. That gain was fully expensed in the quarter because of the refinancing. Looking at the full year, $2.1 billion of EBITDA. As I mentioned, that's 12% up on the same period last year or on last year. Per share, you can see it's up 24% given the share buyback we did in mid-2019. For 2020, we have a lower share count than what we had for average on 2019. CFFO, as I said earlier, $1.5 billion. We have paid in total $430 million of cash taxes during the year in 2020. We had a positive working capital release during the year of $61 million, which obviously also will help that metric somewhat. Despite a very turbulent and volatile year in terms of macro backdrop, we still generated very strong free cash flow before dividend payments of $450 million. We had investment levels of just over $ 1.08 billion During the year spread across oil and gas and renewable investments. We will come back to that. We had a net result for the full year, adjusted again for certain one-off items which are non-operational related. We recorded 11% increase, so $280 million in after-tax net profits. If we look a little bit closer on price realization in terms of crude oil, as I mentioned, an extremely volatile year in terms of oil price volatility, particularly at the height of COVID during March, April, May, it was extremely volatile. If you look on the graph to the right here and look at what the Dated Brent was for the average of the year, $41.80, and what we have realized for the full year at $40, you can see there are really three key elements driving that delta of 4%. One is timing effect. Every time we lift a cargo, it is being priced over the subsequent five days, and there is a bit of randomness within that, whether you hit an increase in price curve at that point or a decrease. That will impact your realized prices. On average for the year, we have been on a declining curve rather than increasing curve. That led to $0.70 discount compared to the dated average for the full year. Also during particularly April and May for us, which is actually when we had very high liftings, as you can see on the left-hand side here of the graph, we had to accept significant discounts on our physical cargoes just to sell the cargoes effectively. It was a very tricky trading environment at that point in time. If you strip those discounts out and annualize it, that equated almost to $1 discount for the full year just for those two months, $0.70. If you take that as an outlier, if you like, and then look at the normalized realized prices on the physical crudes we have been selling, then we've had on average a $0.50 discount versus the Dated Brent over this period. If you then look at the geographical spread, our marketing team here in Geneva and also the operational team in Norway have done a great job. As you can see here, we are selling pretty much globally our cargoes. Quite a big chunk goes to various countries in Europe. About 40% goes into Asia, and we even had a few cargoes going to North America. You can see it's a good natural spread, and we are not reliant upon any one single customer to achieve the prices that we are achieving. Similarly, on the bottom right here, you can see the credit risk we are taking upon us. We’ve had no bad debt on receivables on the cargoes that we are selling. You can see three-quarters of the customers we are selling to are credit rated A or better, and one-quarter is either investment grade, or if not investment grade, then we sell backed by financial guarantees. On the left, you see the spread of the crude we’ve sold. We sold the 72 cargoes during the year. Obviously with Johan Sverdrup being the highest producing field, it’s also the highest volume of sold cargoes, 56%, and Edvard Grieg 37%, and Alvheim still making up a decent size of this pie. Looking in more detail on the cash flow generation during 2020, as I said, $1.5 billion of CFFO generated for the year. The investment levels, $1.08 billion split, $908 million on oil and gas, which includes the $125 million on the Wisting acquisition. Renewables, both the Leikanger hydropower project in Norway and the Metsälamminkangas wind farm in Finland amounting to $100 million of expenditure during 2020. That's what's generated the free cash flow of $450 million pre-dividends. As you can see here, cash dividends paid out during 2020, $318 million, which is made up of three quarterlies dividend payments relating to the 2019 dividend and also the last quarterly dividend from 2018 dividend. We delevered debt, $100 million. We started the year at $4 billion and ended at $3.9 billion as previously mentioned. Through the refinancing and also the corporate facility we entered into in the height of COVID to secure additional liquidity buffer, and also the renewable facility we entered into in January last year, we have incurred total financing fees of around about $35 million of fees during the year. Talking about refinancing, you can see here, on the top right, the available credit lines we now have put in place with this new corporate facility, which we announced just before Christmas. We have in place $5 billion of committed credit lines out to November 2022. These credit lines are made up of a blend of term loans and a $1.5 billion RCF. The term loans start to mature after two years and then three, four, and five years. That's how you get the amortization schedule that we're showing here out to November 2024. Not only has this shored up the funding capacity to execute on the program that you've just been presented with, it also gives us good liquidity headroom to capture any inorganic, any M&A opportunities that may arise and also give us liquidity for any unforeseen events. For example, as we saw last year with the COVID impact. We've done all this on improved terms. The RBL margin we were paying was 2.5%, and we are now at 1.6%. Also this facility has been set up such that we can now issue unsecured bonds at the pari passu level with the bank debt. Also importantly, we have an ESG framework within this so that if we outperform on some of our ESG metrics, that will have a direct impact on the margin that we are paying to our debt providers. On the left, you see a projection here on where we anticipate to come out at in terms of net debt EBITDA metrics at year-end 2021 and 2022. 2021 is modeled on our oil price bracket from $40-$60, and 2022 is from $45-$65 Brent. You can see that we're deleveraging under any of those scenarios and heading towards a one-time net debt EBITDA, if not at the end of 2021, then certainly at 2022. This is just to recap on 2020 performance. We've delivered better than guidance effectively across the board here. The expenditure levels are down around about 25% compared to what we guided at the CMD. That's also partially driven by a weaker NOK than what we assumed at the CMD. Also partially driven by the fact that we have deferred some of the expenditure from 2020 into 2021 to increase our liquidity flexibility at the height of COVID during the summer. Before going into the 2021 guidance, this is our financial model. It's a fairly traditional model, I would say. Obviously, everything is underpinned by the asset base that we have, you heard how those keep outperforming very good quality oil and a good EBITDA margin. Also our balanced capital allocation strategy where we prioritize dividend growth, as you heard, with increasing dividends, but also growing organically and also being able to latch on inorganic growth opportunities. As you'll see a bit later on, in terms of free cash flow generation, $10 a barrel free cash flow is the average for the next six years. Almost at any oil price scenario, this portfolio will be free cash flow generating. Of course, sustaining dividends is a key priority for us. Even below $50 oil, we can certainly sustain the $1.80 dividend we have proposed to the AGM. Of course, the aim is to do better than that and to increase that dividend over time. The highlights for 2021, before we go into some more of the details. The dividend we have mentioned, we are projecting a CFFO generation of $1.5 billion-$2.3 billion for the full year. That's at oil prices between $40 and $60 Dated Brent. The midpoint of that should leave us with a net debt EBITDA at year-end 2021 of 1.2 times. OPEX, we have guided on or been mentioned already at $3. The capital budget for this year is $1.1 billion on oil and gas, both CapEx and E&A, and around about $70 million on renewables and reforestation. Going into some of the more detailed guidance. I won't go through all the numbers. I will focus on our center data point of Dated Brent of $50. You can see here, at $50 Dated Brent, we are expecting actually to realize around about $50 per barrel, which would generate around about $3.3 billion in total revenue for the full year. We guided on cash operating cost is around about $200 million in absolute terms, and other costs is business interruption insurance and some smaller items. G&A still runs at extremely low levels. Again, an industry-leading metric for us, $ 0.50 per barrel G&A. Around about $35 million in gross in absolute amounts, which is similar to what we posted for 2020. That leaves an EBITDA margin netback of $46.40 on a $50 Dated Brent. That would equate to roughly $3 billion in generated EBITDA at $50 Dated Brent for the year. Moving on through the income statement, getting to a net profit. We are estimating depletion rate of below $10 now, given the increase in resource we've seen on Edvard Grieg through last year. When we guided this at CMD last year, it was up at $ 11, we've improved that quite a bit. Financial items, around about $2.40 per barrel. This includes certain assumed losses on our interest rate swaps, which at the moment, when you do mark to market, are sitting out of the money. Profit before tax on $50 Dated Brent, $ 34. We have a tax charge here of $26 a barrel, which would equate to $1.7 billion tax charge to the income statement, of which $ 1.1 billion would be current, the delta would be a deferred tax charge to the income statement. That would give us a profit after tax of just below $8 per barrel, which would equate to around about $520 million. Just touching briefly on tax. We have still a high value of tax assets in Norway amounting to $1.1 billion. This is effectively going to benefit us as we move forward in that you have a six-year depreciation schedule in Norway on capital investments. When you take the tax value of those undepreciated tax balances, it would amount to $1.1 billion. Looking then a bit further into the tax picture for the company, you can see in top left that we posted $512 million for current tax in 2020. Depending on what oil price scenario we look at in 2021, we are estimating to have current tax charge of between $700 to $1.6 billion, depending on whether you look at a $40 or $60 environment. When you then look on top right, this is the tax payments that will flow through our cash flow statements in 2021. What you see in dark red here is already locked in. These are tax installments we have to make relating to the 2020 current tax charge. You look at our balance sheet today, we have posted $440 million of tax liabilities. Those are those red bars that we pay in the first half this year, $360 million, and then a catch-up payment in November of $80 million. Those shaded bars will depend upon what oil prices we have in terms of what cash tax installments we will make in the second half of 2021. You can see at a $50 Brent, we estimate to pay around about $150 million at a $50 Dated Brent in Q3 and around about $400 million at a $50 Dated Brent in Q4. Clearly, this will depend upon what oil price we achieve. In terms of 2021 investment levels, you can see that in the blue bars on the bottom here, $260 million of E&A and $850 million on CapEx. You can see on the middle bottom chart here, the earned tax credits we get from those investments. With the tax changes we've had in Norway, for every dollar you now spend on CapEx, you get $ 0.73 back immediately in the year that you incur that investment. That's the CapEx bar you see here of 73.1%, $ 620 million. The regime on E&A spend has not changed, that is a 78% tax credit on the expenditure we incur. All in, you can see the sum of all of this, including the historic CapEx depreciation coming through this year. We have close to $1.3 billion of tax credits to offset against our EBITDA generation, and it's on that basis that you calculate your current tax. That leaves us then with a funding and liquidity picture like this. Again, focusing on the $50 picture, $1.9 billion of CFFO for the full year. The total investment program that I went through on the previous slide will amount to $18.3 a barrel or $1.2 billion in total. That therefore gives $10.60 in terms of cash flow available for dividend payments, which is around about $700 million of free cash flow pre-dividend payments. The dividend proposal we are putting forward to the AGM of $1.80 would equate to $454 million of cash dividend paid out during 2021. That will therefore leave us even on a post-dividend level with a free cash flow generation of $3.7 a barrel, which would equate to around about $250 million of de-leveraging debt, effectively post dividends at the $50 Dated Brent. You can see between the $40 and the $50 scenario here, that we will be covering everything, including dividends at around about $43 Dated Brent for the full year, to leave us free cash flow neutral post dividends. In terms of the CapEx program for 2021, I've been through already, but if you look at the dark red bars here, that is the committed 2P CapEx we have in the portfolio. Post 2021, it really centers on Johan Sverdrup to a large degree, given that all the other projects will have been completed at that point in time. Our all-in 2P development CapEx is around about $1.5 billion to produce out our remaining 2P reserves. The light red bars here, there's obviously less certainty around that. These are the growth projects that Dan and Kristin took you through. Of course, some of this still requires more de-risking, but we are estimating, give or take, another $1.5 billion pre-tax of contingent resource CapEx over this period. Clearly, the uncertainty range around that is still significant, the aim as we go through this year is to narrow that band. What does that mean for us in the medium term? We've talked about the free cash flow breakevens we have over the next six years, on the chart to the left here, you see how that pans out on a year-by-year basis. The previous slide, you saw a high CapEx year this year, on the 2P level, the CapEx is starting to roll off significantly. What's also key here is that even if we go after all these growth projects that we have outlined in the presentation, we are still going to be free cash flow breakeven at $15 Dated Brent. All these growth projects are breaking even full cycle between $20-$35 Dated Brent, with achieving an unlevered IRR of 8%. Clearly that's money well spent, and you can see that we will be very resilient even in a lower oil price environment, even if we go after all of these projects. On the right here, you can see at our price range from long term $45-$65, we expect to generate $8 billion-$11 billion of CFFO over this period. In terms of how we are going to allocate that cash generation, a significant element will still go into resource and production growth. We estimate around about between 40%-50% of that CFFO generation will be allocated towards that. Clearly, the uncertainty there is in terms of how much E&A we spend and how many of these growth projects we are going to sanction in the end. The picture on that front will be much clearer as we move through this year. That will therefore leave between 50%-60% of the CFFO to be allocated between dividends and debt repayments. That 50%-60% is going to translate into a free cash flow of between $4 billion-$6 billion. We will then allocate that, as I said, between dividends and debt. The aim, of course, of the $1.80 dividend is to grow that year-on-year. We can do that and still leave a very conservative leverage on the balance sheet. We are projecting to stay certainly below 1.5x and ideally below 1x as we move out in time over this medium-term forecast period. Extremely solid position for the company, strong cash flow generation underpinned by extremely good producing assets. Just quickly, just for housekeeping, to highlight the risk management approach we have. As most people will know, we do hedge our NOK exposure on the CapEx element of the Norway portfolio. In terms of insurance, we do all the traditional insurance policies that people would expect us to do. Importantly, we have also put in place business interruption insurance both on Johan Sverdrup and Edvard Grieg, given that those two account for the majority of our production volume. My last slide before I hand back to Nick is just to demonstrate that the value creation is key. Not only is value creation key, it's also key that you actually return that back to shareholders. I think that's what this graph demonstrates very well. Over the last 10 years, including the 2020 proposed dividend, we have returned around about $4 billion of value back to our shareholders. That spread $1.4 billion in cash dividends. With the EnQuest and IPC spin-outs, that's another $1.1 billion. In 2019, we did a 16% share buyback of $1.5 billion. We have a balanced approach across this, although the dividend policy is the one that's set in stone. What we proposed in dividends of $1.80 is very much in line with that. That was my last slide, and I will now hand back to Nick Walker for some concluding remarks. Thank you. Well, good afternoon again. You've got me back, and I've just got one slide before we move into Q&As. I just want to reinforce the messages that we've got across this afternoon and I finished up with earlier. We are delivering strong growth. Our business is going to go over 200,000 barrels a day by 2023. I hope you've got the sense we have a portfolio that can sustain that with upsides and new projects. We will continue to explore beyond that to build growth in the longer term. Our business is also resilient, long-term, low operating costs of $3-$4. No one else is close to that, so industry-leading. The resilience of our business means that we have very low free cash flow breakevens. You can see $10 a barrel over the period 2021 to 2026, which makes us generate significant free cash flow. So we've got the ability to fund growth, conservatively manage debt, and deliver a sustainable and growing dividend. Just to reemphasize our proposal on dividends, our recommendation on dividends is $1.80 a share, an increase of 80% on last year. Our aim is to grow and sustain that in the long term. We have a business that can sustain dividends even below $50 a barrel. A very resilient business, able to deliver significant shareholder returns over time. Then as importantly also, is that we have a sustainable business, and we're delivering on our decarbonization strategy. We've accelerated the point at which we become carbon neutral to 2025, and we've got real activity that supports that, and we're going to be able to make that happen. On top of that, we can't run our business without being safe and responsible, and we put huge effort into that. The message is, we've got a growing business, it's resilient and it's sustainable. It's set up to deliver long-term shareholder returns and be investable and relevant into the future. That's the summary. Now what I'd like to do is we'll turn to questions. Before we go to the operator, though, what I'd like to do is just remind everyone the opportunity to ask questions online. At the top of your screen, I think there should be an ask question. If you wish to submit online, you can do that. As Ed mentioned earlier this session, you can send an email to lundin-energy.com and ask a question that way. First of all, we're going to go to the operator, Tracy, who's going to manage the Q&A session, and we'll be joined separately with my colleagues also who've been talking today. We look forward to taking your questions. Tracy, over to you. Thank you. Ladies and gentlemen, if you wish to ask a question over the telephone lines, you will need to press the star and one on your keypad and wait for your name to be announced. If you are on the telephones and also listening on the web, please mute your computer to avoid any feedback. That's the star and one if you wish to ask a question over the audio lines. We have a question online from Anish Kapadia from Palissy Advisors. Hi. Good afternoon. Thanks very much for the presentation. My first question is focusing on your cash flow generation and the outlook for the longer term. It looks like you're going to have very strong cash flow generation in 2021, partly helped by the tax effects. I'm just wondering, looking longer term, how do you deal with the risk of a cash flow decline? Partly as the tax effects roll off, but I'm thinking kind of five or so years out when you've got the potential for significant declines in these assets to come through as natural declines kick in. Just really asking, how do you see the outlook for cash flow, and is there a risk of some sharp cash flow declines kind of five-plus years out? My second question, somewhat related to this, was whether you could comment on your exploration performance over the last five years or so. Clearly, you've had, over the longer term, very strong exploration success. When I look at the numbers over that kind of shorter-term period, I think you've only added about 5% of what you've targeted on my estimates. Just wondering your kind of thoughts around this, and does that mean that you're going to look at more acquisitions similar to that Wisting? Thank you. Okay. Anish, it's a good question. Teitur, why don't you take the first one, and I'll have a go at the second. Good afternoon. Cash tax is clearly a theme we discuss a lot internally, but what we have guided here today on the cash flows from operations, the numbers we showed was between $8 billion-$11 billion of cash flows generation for the next six years out to end 2026. Those numbers are all post-tax. We have paid all the cash tax that we're due to pay within those numbers. The question then is how do we then allocate that between resource growth and production growth versus dividends and debt repayments? Clearly, how much we allocate to resource growth depends on the opportunity set that we have in the portfolio. I think you got a good feel from the presenters today that we have quite a number of low-hanging fruits there. Clearly, when we invest in these projects and they have a breakeven of between $20 and $35, including an unlevered IRR of 8%, then clearly, in the longer term, that's going to enable you to sustain a dividend even beyond this six-year forecast period, which by the way, is quite a long forecast period when you look at what other companies are guiding on. With those growth projects, the intent will be to solidify and extend the sustainability of our dividend trajectory beyond what we are forecasting here today. The other point to make is on the tax in Norway. The regime is such that for every Norwegian krone you spend on CapEx, you actually get 90 or over, you get 91.4% of it back through tax credits over a six-year period. Even if we, as I mentioned, had to spend, say, $1.5 billion on these growth projects, it is only 10% of that that really comes out of the equity portion of the balance sheet, and the rest is diluded through tax. Maybe I'll pick up the second part of that question, which is around our exploration success. The way I see this is that our growth comes in a number of areas. It's not just on pure exploration, but it's on growing the fields that we have an interest in, and exploring around them. We've seen strong growth in those over recent years. In fact, Edvard Grieg, Johan Sverdrup, and Alvheim have all continued to grow, and I think we're going to see more growth there. Quite a lot of our activity around the Edvard Grieg this year is around progressing that too. Second is around, and some of that activity is sort of exploration-led. Then we also focus on exploring in the mature basins in Norway, and a component of our exploration budget goes to that. We have the third element is around sort of the frontier areas, and higher rewards, higher risk opportunities where we also have a component of our budget going to. If you look over the last five years and average it, our resource replacement ratio over that period of time has been 150%. That means that for that five-year period, we've added 50% more than we've produced. We've grown the business. I think you raise an interesting point or an important point around big exploration success. I think it's true to say we haven't had that over that period of time, but we have made quite a lot of smaller scale opportunity successes. For example, Iving that we made last year, which looks to be of commercial size, and we will appraise this year. We continue to find quite a lot of resource around the Edvard Grieg area and in the Alvheim area. We have had success, but not on the big scale. It comes in a number of areas. To me, it's not just the big scale success. Of course, we'd like that, but it's continuing to show progression on the whole portfolio, and I think we have done that. The question around acquisitions, of course, if the right thing comes along at the right price, then we will look at them. It has to meet our strategy. We're looking not for mature assets, but for younger life assets, maybe undeveloped or in the early in the development phase. We also have to be able to create value doing it. We have looked over the years at quite a number of acquisitions. The challenge has been is that we've had to pay essentially full value for them and pay dollars for barrels. That doesn't create shareholder value. If we can find the right thing at the right price, we'll do it. Just like the Wisting acquisition that we did last year, we buying 10% of Wisting, a big field in the Barents that's heading towards development, and I think it's a great acquisition. We did that at $1.80 per barrel purchase cost, and that's, I think, a great piece of business, and I think we'll be able to make good value at that. If we find more of those opportunities, for sure, it will be a component of what we do, but I think it's those three elements of exploration plus acquisitions drives the growth, and I think we've been able to keep doing it. It is a big challenge, but we have a good portfolio, and I'm excited by the program we have ahead of us. Anish, I think unless you've got a follow-up question, that's how we'd cover both of those. That's great. Thanks very much. Thank you. Once again, ladies and gentlemen, if you wish to ask a question over the audio lines, press the star and one on your telephone keypad. We have no further questions on the audio lines, sir. Hand back to yourself. Ed, I think this is for you to take on now with the. Yes, indeed. Thanks very much, Nick. Thanks, Tracy, for that. We have a few questions on the line here. I'll run through them, Nick, and then you can distribute them out as relevant. From Karl Schjøtt-Pedersen at ABG, "Can you provide some color on the Ivar Aasen decline profile, to increase production from Edvard Grieg? How firm is the decline profile?" His second question is on the decarbonization strategy. "Can you elaborate on the rationale for investment in reforestry? Is it carbon reduction, or will it have an impact on revenue or cost reductions? Daniel, perhaps you do this the first, and Zomo will cover the second. No problem. Ivar Aasen, I think every field will move into a natural decline phase, and so we saw some of that through the course of the tail end of the year where we saw some additional capacity. The operator are putting two new infill wells on stream. We'll see those coming online later in Q1. The next program is beyond that. I think we're in a phase with Ivar Aasen where the decline will start through the course of the year, and we've taken that into our production profiles. I think the important piece to note is that we will use every single element of the available capacity on Edvard Grieg. Where there is a period where they're underperforming or where there is a period where there's any available capacity, we have ample well capacity to keep the facilities full on Edvard Grieg. Zomo? Yeah, it's a good question. For the reforestation projects, the primary purpose of that investment is to secure a future stream of carbon credits that we can use and retire for our own purposes to achieve carbon neutrality. Compared to the alternative, which is just buying offsets from the market every year at potentially very high prices, it should deliver some savings against that alternative. Of course, if we do decarbonize further and the way that the carbon is captured is higher than we expect, then any surplus we could potentially monetize. That is not the aim of the strategy today. Thanks, Zomo. The next question is from James Carmichael at Berenberg. "How long is the shutdown in Q2 at Johan Sverdrup, and can you provide a bit more color on the work you need to do before changing phase two guidance?" He also asked a follow-up just on phase two costs and if we're going to see them coming down like we did in phase one. Daniel, why don't you take those? I think Phase 2 costs, if we start there, then we'll touch on the capacity. Phase 2 costs are down around 50% from the original PDO. I think it's too early at this stage to talk any further around the cost reductions, and I think we stay at that level until we get further down the project delivery. Through the course of 2021, we should see more around where we are on project delivery. I think today we stay on track with the cost estimate, and that will continue through the course of 2021. I think on the capacity side of things, as you're aware, in November we lifted the capacity for Sverdrup, and we've done a range of study work on the Phase 1 capacity, and that has lifted it to 535, and we've got the water injection project. Because that's so new, we need to do a little bit more work on the common facilities around export. I know we're all aligned within the partnership to look at every single opportunity to increase capacity from Johan Sverdrup, and so that work needs to be completed. I think we'll hear more about that through the course of 2021 and 2022. We also need to do the same on the Phase 2 facility as we move through the construction phase. I think hold on that thought for a little bit until we complete that work, and then I think there's more news to follow after that point. Okay. Thanks, Daniel. The next question, there's a couple of questions here from Peter at Three Bridges Capital. Just wanted to clarify the impact of the tax incentives this year. Could you sort of go through the tax impact on this year with the new incentives, and then on the 2022 incentives for post-PDO sanction? The other one he asked, wanted to know about was, with production going over 200,000 barrels, cash flow is going to be around $2.5 billion, while CapEx and dividend will be around $1 billion. What are you going to do with the extra $1.5 billion? What's the plan for the free cash flow? Is it M&A to build out the 3P and 2C, or are you going to be doing buybacks? It's tax incentives and giving an overview of how we're going to benefit from that, and then how we're going to use excess free cash flow at the $200,000 a day period for us. Teitur, why don't you take those for us? I can do, yeah. On the taxes, the rules are such that the government introduced them last year. It applies to any capital expenditure we incurred last year and this year. Within the special petroleum tax regime, which is the 56% tax regime, we can 100% depreciate the capital cost against that tax base. Also, we can 100% depreciate the uplift, which in the old regime was 20%, and in the new regime was 24%. That 24% uplift on top of the CapEx you actually spend can all be 100% depreciated in the year you incur that investment. That is set against the old regime where you had to depreciate those two deductibles either over six years or four years, respectively. These new rules will also apply, as Kristin mentioned in her presentation, on any new PDO which is submitted before year-end 2022 and which the government has approved before 2023. That is why it is key for us that some of these growth projects that we reach that finishing line before we are timed out of these very well-thought-through tax changes from the Norwegian Parliament. On the second question, in terms of cash flow generation, what we are saying here is over the next six years, we are projecting to generate free cash flow generation between $ 4 billion-$6 billion cumulative. If you look at that over the six years, that is going to be somewhere between $660 million per year-$ 1 billion per year in free cash flow, depending on which oil price scenario we look at. You set that free cash flow in the context of the dividend proposal we put forward last evening of $1.80, which translates to just over $500 million of cash dividend out. That means out of the annual free cash flow we generate on the current dividend proposal we have in place, we are paying out somewhere between 73%-50%. That hopefully gives you a feel for that we have ample capacity to increase that dividend year-on-year at the same time as leaving firepower to deleverage the balance sheet further and also to latch on any inorganic growth M&A opportunities. We are literally setting the business up so that we can explore all those avenues in parallel. It's not an either/or situation for us. Okay. Thanks, Teitur. There's a few shy people now, so they're going to be anonymous question. I recently saw that you took a stake in the Wisting field. Are there any other stakes for sale, and would you like more? Would you invest more in the Wisting field? Maybe I'll get that. We took a 10% piece of Wisting and it's great piece of the field, and we're excited to be part of that. I think we'd like more. If more comes available and we get a good price, then we'd certainly take more. I think as I mentioned in my previous question that I answered, acquisitions are something that we look at if we can find the right thing. To reiterate, it has to be the right quality, so it needs to be undeveloped or early life where we can add value and create value. If we can find the right things, as Teitur mentioned, we've got capacity within the balance sheet to do things and we will do it. Ultimately, we have to be able to create shareholder value doing it, and we have to get it at the right price that we can do it. If things come along, for sure, we have the capacity and may well do them. Thanks, Nick. The next one's a three-parter again. Could you expand on the potential development options for Alta? The second one is, can you also discuss the high-level economics on the Wisting project? Return hurdles, breakevens. What do you expect to see from that project? Thirdly, do the CFFO and free cash flow five-year figures given include the 2C growth project? Kristin, why don't you get Alta and I'll take the second, and Teitur will do the financial one. Yeah. As I said in my presentation, our base case for Alta has been subsea tie-back to Castberg for some time. We did start two focused feasibility studies last year in light of the incentives we had to try and accelerate development. The two options that we have been studying, and which we are concluding on later this winter, is a tieback to Goliat and reuse of an FPSO. To pick up the Wisting question, we don't disclose the economic hurdle rates that we use. Suffice to say, we need to have a project that's got robust economics to low oil prices and a low breakeven oil prices, and I think the other partners would need to too. We believe the project has that already. We wouldn't have invested if we didn't think it was going to move forward to development with attractive economics. We think it will. I think when we get closer, obviously those sorts of things will be disclosed, but it's too early to really talk about sort of economic metrics that we'd see from that. We've been taking a very disciplined approach as a company about doing projects that are robust to low prices. That's very forefront of our mind in anything we do, actually. It would be applied to that, too. Hopefully that answers the question, and then, Teitur, you'll pick up the financial one. These CFFO numbers we are showing from 2021 to 2026, they do include the contingent resource development expenditure, which obviously means that those projects will build up a tax shelter for us, which therefore reduces the cash tax that sits within the CFFO numbers. If we just took the 2P scenario without any of the growth projects, then clearly we wouldn't have those tax shelters. Well, similarly, we wouldn't have the CapEx incurred in the first place. The free cash flow picture would be accretive in that scenario in the short term. As I said, we are doing and embarking upon these growth projects because in the longer term, we believe it's improving our dividend capacity and the general cash flow capacity within the portfolio. Thanks, Teitur. The next one's a slightly cheeky one. With 200,000 barrels a day sustained production, it's incredibly impressive, but what is your bigger ambition? Do you have an ambition to go beyond what you've put on the page there that you could enlighten us with? I think it's a good question. I think we'd obviously like to go further. Our ambition is to get there and stay there. I think if we can do that, we've done a tremendous job. That is very much now the focus of the business. I think if you look back over time, we've continually lifted our outlook and long-term growth targets. We would look to sort of conservatively give an outlook that we can deliver and hopefully beat. That's going to be our target. Let's see how the business develops and see where we get to. We think we can sustain over 200. That's the aim for now. Let's see how things go in the next few years. Thanks, Nick. Next question again is a shy person, anonymous one. How certain are you in the nine development opportunities listed reaching PDO by the end of 2022? Do any of them fail to meet your investment criteria if they miss the deadline for the tax incentives? Does your opportunistic approach to acquisitions include looking outside of Norway, potentially? Kristin, why don't you pick the first part of that, and then I can pick up the other one. Yeah. No, several of these projects actually do require de-risking this year, and that's the acquisition of real hard data through drilling, exploration, or appraisal drilling. It's simply about finding enough volume to have a commercial project, and that's the aim of much of the work that we are doing this year. This year is a very critical year for deciding on the destiny of six of these projects, at least. Three of them are definitely moving towards sanction, either this year or next year. The other projects all have an element of either gaining production experience or hard facts through the drill bit. Good. Then the other piece, would we look outside Norway? No. We've firmly said that our focus is on Norway. I think being a pure-play Norway, I think it's a great region to have a business. I think we've seen some of the reasons for that in the challenges for the whole of society in the last year. We have a very strong business. We think we can continue to keep growing and build a portfolio of opportunities that allow us to grow into the future. We think there's enough to continue to keep doing it in Norway, and so that, for now, will be the focus. Okay. Thanks, Nick. The next one is from Al Stanton, RBC. With around 700,000 barrels a day at Sverdrup and 100,000 from Grieg, you get to working interest production of about 205,000. Your outlook for 2P production in 2023 plus looks relatively unchallenging on slide 35. Should we be cautious on everything else, i.e. decline rates? What about Sverdrup? Should we assume a peak or a plateauing, and for how long? Daniel, do you want to have a go and maybe I'll chip in? Yeah, I think it's a good observation. I think you see it in the long-term production chart on how much upside there is beyond the 2P. I think we're comfortable in the 2P scenario to get to 200 and beyond 200. I think if you look at the history of Johan Sverdrup capacity, look at the history of resource replacement on Edvard Grieg, I think you can take a view on what the future should look like around these assets. I think it's too early to say exactly what that looks like. We have a lot of hope in not only those two fields delivering more than what sits in the 2P reserves, but on the back of the work in the Edvard Grieg area and the Utsira High, I think we have enough opportunity to both extend that plateau and to ensure that we remain full on capacities on both of those fields. A more pessimistic view on decline rates, I think what we have there is a fair reflection. Today I feel like there's a bit more upside and a bit more opportunity than there is downside, for sure, in that profile. I think, Al, just if I put my perspective on it, I think it's a great question, and we continue to see upside in Edvard Grieg, Alvheim area, and particularly, I think, Johan Sverdrup, and we really haven't started to see the upside in the reservoir on Johan Sverdrup, and it's going to take probably a few years to come. I think we're going to see some further capacity upside come at Johan Sverdrup when Phase 2 comes online. I think there's a good chance of that. I think we're going to be able to push the plateau out further at Edvard Grieg and maybe lift it more as Ivar Aasen declines. I think we've got a lot of activity happening in the Edvard Grieg area that can do that. Then the third piece is Johan Sverdrup reserves. I firmly believe we're going to see growth there. I think there's a good portion of the upside that we show. I'm sure it's going to come. We just can't point to it today. Like anything, we've sort of guided on our two-period reserve base. You can see from the chart there's material upside beyond that. I think if history goes the way we expect, then there's a good portion of that's going to come into reality. Yeah, I'm actually excited by the outlook and you can see it materially goes above 200, and I think there's a good opportunity that we might see that. There's another couple of questions, which I'll group together. Another one from Al. Carbon capture and storage, given Lundin's focus on innovation, are you considering investing in engineered carbon capture? Is it an option for you going forward in terms of the carbon emissions and the further abatement? I'll perhaps take that one, Al. It's a good question, and our focus is to become carbon neutral in the production of our barrels, and we have put in place the measures to get there, actually. We've committed to everything that's going to achieve that pretty well. We've got a little bit more investment into renewables to achieve it, but pretty well we've got everything happening to make that happen by 2025. We haven't looked at carbon capture and storage. I think it's a different issue. It's not currently on the radar screen for us to invest into. This one is from David Round at his new shop, Stifel. What comfort can you give around the dividend in future, given the ongoing volatility in oil prices? You mentioned sustainable below 50, but has Sverdrup production history delivering free cash flow given you more confidence to sustain the dividend next time if we're to head again towards 40 or even 30? Is there some flexibility? How flexible are we, Dan? Teitur, do you want to have a go and maybe I'll give my perspective, too? I can do. It's a good question, as we showed on our slides for this year, we are free cash flow breakeven post-dividends around about $43 a barrel. I think there's some room to drop from $50. If you cast your mind back to this time last year when we also announced a $1.80 dividend, which at that point in time was predicated on our midpoint oil price of $65 Brent. We are now back to that same dividend level, we are now basing it on sort of a midpoint of $50 Dated Brent. That just demonstrates how much the portfolio has actually improved over this year with increased reserves in Edvard Grieg and increased capacity both on Edvard Grieg and Johan Sverdrup, that's clearly filtering through on the cash flow generation of the company. That's why we feel very comfortable with $1.80 now. As I said, we can certainly sustain that for a period of time, even with oil prices significantly below $50. Clearly at anything north of $50, the aim would certainly be to grow that dividend over the next few years. Yeah, I think I back that up. The focus is to We are able to sustain dividends below $ 50, Our aim is very much to grow the dividend over time. We think we've got the business that can do that. It's a good outlook. I think that you can see the resilience of the business and the cash generation of the business that can achieve that. Good. This is from James Hubbard at Deutsche. If the IEA Sustainable Development Scenario turns out to be overly optimistic, and governments truly embrace net zero 2050 and oil consumption falls much more rapidly than in the IEA scenarios, would this cause any obvious change in your 10-year plus strategy? I think what we've tried to do is make a strategy that works, even if we end up in the 2-degree scenario. If we can be the best in terms of cost, lowest cost, then low oil prices will be resilient. If we can make ourselves carbon neutral, then we'll attract investment dollars. Those are the 2 levers we've got to drive this. I think there's a massive challenge for the world to move from the energy mix we have today to the future, and it can't happen overnight. The time frames we're looking at on the IEA forecast are 20 years, which is a long time. We can't predict the future, but I think if we can do it lowest cost and lowest carbon, we'll be resilient in the future. A follow-up to that is around TCFD. Are you going to be TCFD compliant or reporting this year? Zomo, you can get that? Yeah. Thank you. We are aligning our reporting with the recommendations of the TCFD this year, and you will see in our sustainability report for 2020, that'll be published in March, our response to the TCFD recommendations, which look at the range of climate change risks that we have potential exposure to, how we are managing them, and shows that hopefully, as you'll see, that we don't have any material residual risks against some of the big climate change issues given the low carbon, low cost environment that we are in. Very good. Thanks, Zomo. Carl from ABG again. When should we expect an update on reserves at Sverdrup? Daniel, do you want to take that one? Maybe Per Øyvind can take that one. That's probably better to Per Øyvind, actually. Yes, thank you. There are many things in place to accurately monitor the performance on Johan Sverdrup, and to continuously update models and forecasts, and so forth. I think the one key thing is obviously a PRM 4D seismic survey and so forth. I think it'll be an amazing story of how well you can monitor reservoir performance. The key thing, the most important thing for determining resource outlook is water breakthrough. That's not expected until, I guess, quite a few years into the future. We don't really expect anything in the next couple of years. The message is going to take a bit of time because it's such a big field and it takes some time to see the response. We'll have to be patient, unfortunately. We're not very, but we have to be patient on this one. Thanks. There's a quick question here, which is going back around the subject of carbon capture and things. Would we ever look into offshore wind projects, fixed or floating, for future developments? I think maybe I'll take that one. We've focused, for now on matching our electricity usage that we're going to have, which is significant from our power from shore projects, which is around 500 GWh per annum of electricity usage. As Zomo went through, we've done two projects that count for about 60% of our requirements, a hydro project in Norway, and a wind farm project in Finland. We're currently today looking for other projects, and I think we're getting quite close to one that would be another onshore wind in the Nordics. That's been our focus. I think the scale of the opportunity, I think the economics of those things are more conducive to the scale of the things that we're looking at. We have been looking to balance just our own power usage with our own generated renewables. I think if you're going to make offshore wind work, it has to be on huge scale and economies of scale to make it work. It's not something that we felt that we want to get into. Let's not forget, our business is really focused on oil and gas. That's our core business. We've done the renewables really to enable our decarbonization strategy. It's not really a change in business direction. The value out of our business is going to come from oil and gas. To enable our business in the long term, we've put in place our decarbonization strategy, which is the right thing to do, and it does bring value with itself. We're not changing direction to become a big wholesale renewable power generator. The key focus is oil and gas, and so we haven't so far chosen to look offshore. Thanks. There's another one here on the Ivar Aasen declines. What's assumed in 135,000 barrels a day Edvard Grieg upside opportunity in terms of Ivar Aasen? Is 135,000 barrels a day at Edvard Grieg a ceiling? Daniel, do you want to take that? Yeah. We've proven the facility can operate at that level, so Edvard Grieg can operate at 135. Of course, there is a full capacity on Edvard Grieg of 145 today, including Ivar Aasen. We have a range contractually where we're at 95 today, up to 135, depending on whether Ivar Aasen fill their capacity or not. In our production guidance for the year, as I showed in the slide, we show an uptick towards the second half of the year, which is a combination of increased capacity on Edvard Grieg. We do assume a small amount for Ivar Aasen, and we also have Johan Sverdrup stepping up in the second half of the year. It really depends. The upside is what happens in the first six months of the year on Ivar Aasen. There's a significant amount of room on Edvard Grieg to fill that full capacity, and we have well potential plus new projects which will be able to fill that potential once it is available. Thanks, Dan. This is actually the last question I've got. It's from Tom Sedgwick at UBS. It's a three parter. Having rebased the dividend lower, what drove the decision for a sharp rebound straight back to pre-COVID distribution levels rather than, say, a lower base supported by buybacks? The second bit, can you provide some context on how potential plans for the Norwegian government's tripling of carbon taxes by 2030 will impact the business? And thirdly, can you comment around the risks of cost increases facing the Wisting project and concept selection given the recent reports in Upstream? Teitur, why don't you get the first, I'll do the second and Kristin can talk about Wisting for us, I think. Okay. Yeah, the first one on the dividend increase. As I said, with all the improvements coming through on the portfolio, at the end of the day, the dividend capacity we have is always going to be driven by the portfolio performance. The financial framework we have is fully reliant on the assets performing. With the improvements that we've seen as we've been through with the resource increases in Edvard Grieg and capacity increases. When we look out, we don't set dividends on a year-by-year basis. We look over a longer horizon and say, "Okay, what is a sustainable growing dividend within this portfolio performance and within this financial framework. On that basis, we landed on kicking off again at $1.80, feeling that we have sufficient room to grow that dividend over the next few years, at the same time as being able to delever the balance sheet to sustain that investment grade credit rating, and also to allow for inorganic growth if those opportunities come along. When we baked all that into the decision-making, we felt $1.80 was an appropriate level to kick off from. Then to just address carbon taxes, so everyone's aware. Norway today has the highest carbon taxes in the world, around $100 a ton. It was announced recently, the intention to lift them to around $240 a ton by 2030. I think if you look back, Norway's been at the forefront of this, and I think it's been very farsighted of the government to put in place high carbon taxes, because I think it's encouraged a change in behaviors and caused people to look at things like electrification that we have done. I think the motivation to increase taxes is clearly to reduce carbon emissions, and I think it will cause further change in behavior. Norway today is at the forefront of the industry. It has some of the lowest carbon emissions in the world, if not overall the lowest certainly for the offshore industry. It's been driven by that policy drive, I believe. Of course, lifting carbon taxes again will drive further change. If you look at us as a company now, we'll have over 95% of our production powered from shore by 2023. A big portion of our emissions have gone away. Really, the impact on us of this carbon tax increase from a financial perspective is very, very minimal. It just enhances the value of what we've been doing around electrification, and makes those projects even more attractive. I think it's a good thing, and I think it will cause change. Really, we need to see the rest of the world move in the same direction. Really, we need to see other countries embrace and put in place higher carbon taxes to cause worldwide change in the way oil and gas is produced. Maybe, Kristin, you pick up the question around Wisting as well. Yes. Okay. Yes, the context of the range that we saw recently quoted in Upstream was a sentence in the program for impact assessment for the Wisting project that's now out on hearing. I think it's only natural to expect that the range on the capital investment is quite large at this stage of the project. Of course, over the next six months, the definition, uncertainty, and the cost estimates for the project will home in on when the concept select decision gate is passed later this year. I'm very confident we will see not just at decision gate 2, but also when the project reaches sanction, a very robust project. Thank you, Kristin. Ed, any more questions? We've got one last one, actually. I say that, speak too soon maybe, from Anders, from SEB. It's on cash flow from operations and looking at taxes going out. Looking at your indicated accumulated cash flow from operations 2021 to 2026 and comparing it with sensitivities, you seem to pencil in an increasing payable tax rate throughout the period for natural reasons. For something like low 40s in 2021, is it fair to assume payable tax gradually moves towards the high 70s in the end of the period indicated? Yeah. Whether it moves exactly to 70, that, I guess, depends on the CapEx program that comes ahead of 2026. It is true that as our CapEx rolls off, then you're clearly reducing your tax credits that will sit ahead of you because those tax credits are predicated on your prior year CapEx investments. It's only natural that if, say, you stopped investing in CapEx completely, then eventually your marginal cash tax rate would get up to close to 78% over the full cycle. That is the nature of the Norwegian tax regime. Thanks, Teitur. I've got no more questions online or on email. Nick, I'll hand back to you. Good. Well, thanks very much. Of course, everyone who's joined us online, thank you very much for joining our Capital Markets Day today. It would've been nice to have done it in person, and hopefully next year we can do that. It's great to have you all join with us, and good to have the questions. We were very pleased to be able to share the trajectory of the business. Of course, if you've got any further questions beyond this, I think contact Edward Westropp. We'd be more than happy to have a conversation and answer questions. With that, I just wish you good afternoon and have a good evening, and keep safe. Thank you very much.