Good morning and welcome to the Q4 2024 presentation from OKEA. My name is Svein Liknes. I'm the CEO of OKEA, and as previous quarters, I'm also joined by Birte Norheim, our CFO. They will go through the financial section afterwards. We will both also be part of a Q&A session thereafter, and there should be a link on our homepage where you can submit questions or details where you can call into the Q&A just after this presentation. To sum up, the fourth quarter of 2024 was a very strong performance when it came to operations in OKEA. The production was so strong that we also exceeded the previously announced guidance and ended up annually for 39,100 barrels of oil equivalent for the year, and we also came slightly below on our CAPEX guidance, and we will get back to that a little bit later on. Good financial performance. The revenue slightly affected by not having a lifting on Draugen during Q4, not on Brage either. And those liftings obviously will come during this quarter in Q1 2025. So there is just a delay there. And in our portfolio, we completed the sale of Yme that we announced last year. We are developing our projects, predominantly the Power from Shore project and also the Bestla project that I will talk also about a little bit later. And we were also awarded eight licenses in the APA now early in January, whereof two as an operator, which we are very happy with. Key operational figures for the quarter. If you look on safety first, we have an increase there from 0.6 to 1.1 in the serious incident frequency, and that is a rolling average for the last 12 months. And that is because of two single incidents that we had with no harm to people or environment, but there could have been a potential there. So we are investigating those incidents, and that is then dragging up the frequency to 1.1 that we see now. Production, as I just stated, 37.8, which is very strong also compared to the quarter ahead of it and very high production efficiency in our portfolio. And as you can see on the production expenses, also kept at the same level and slightly below what we had in Q3 last year. The thing to note on this slide is, again, high production efficiency on our assets. Q3 was not dominated by, but at least influenced by plant maintenance on quite a few of our assets. And you can see that the graph is now up again, or the bars is now up again. So we are now back into high production efficiency numbers on all our assets. Statfjord area, a slight drop there, but even there above 90%, and that includes a 10-day unplanned shutdown on Statfjord C. Also on the above, you can see the distribution of the production we had, and you can see specifically on Draugen that you'll see the increased performance on Draugen with the, in particular, Hasselmus optimization that we have done. And you'll see a slight reduction in the Statfjord volumes, but again, well distributed and quite stable actually across our portfolio for the quarter. So a quick operational update, asset by asset, Draugen that we operate ourselves. Again, very strong production, very high production efficiency, and we have optimized the gas export plant and also the potential throughput from Hasselmus, which has significantly increased the production and also increased the gas export from Draugen, which is also good to see in the gas market with the increased gas prices. On Brage, we have also had very strong operational performance with very high production efficiency. We did start up a Fensfjord well in November last year, and the performance from that well was a main contributor to also exceeding the plans and targets for Q4 on Brage, and that performance has also continued into the new year. On Brage, we are also drilling an exploration well into what we call Prins and Sognefjord East, and that is as we are drilling a production well to, some of you may remember, a Kim discovery with 2.9 million recoverable BOE. We are now drilling that production well. At the same time, we are then drilling two pilots into the Sognefjord East area to see what that can bring for the future. On the Statfjord area, slight drop in production volumes due to some issues with new wells, but again, above 90% in production efficiency, even though with 10-day unplanned shutdown on Statfjord C. Something we have done though on Statfjord is that we have approved a new drilling strategy, which is a long-term strategy in the Statfjord unit to improve the long-term production, which now we'll roll into and execute on over this year, but also next year. Aasen, again, extremely stable asset. The main thing on Ivar Aasen is to mature and also plan the increased oil recovery campaign with new drilling in 2026. Very good performance from Ivar Aasen, also as a result of an optimized water injection philosophy on the asset. Gjøa, also extremely stable operation, a very well operated asset, and the main thing on Nova has been water injection and also then pressure support in the Nova reservoir. We did restart the water injection during Q4, and we are seeing positive results from that. And in addition, we are also drilling one more water injection well that will now be started in Q1 2025, which again will further strengthen the power, the pressure support for the reservoir so we can increase production from Nova even more. When it comes to Yme, as I just mentioned, we completed the sale in November to Lime Petroleum in Norway, and that was completed in November, and the consideration was NOK 15.65 million and an effective date of 1st of January 2024. In our portfolio, and also as a result of growing as a company, we have the opportunity to do more than just focus on production and growth. So we did the divestment of Yme, and that is because we want to use our resources in areas where we see further development potential and also growth and value creation for the company that fits our strategy even more. So we're very happy to have a successful Yme transition behind us to Lime. We also performed a license swap in exploration licenses at the end of last year. We had a 30% ownership or working interest in Mistral, so we divested down to 20% there, but also then obtained 10% in what we call the Horatio prospect, which is also being drilled in 2025. So that puts more opportunities for us in our exploration portfolio. And last but not least, the award was made in January, but I would like to mention it here as well, is that we were awarded eight licenses in the APA rounds, which is very good licenses. We believe this is what we applied for, whereof two is as an operator, and also two of these licenses are with a firm well commitment, and that will then come in 2026, 2027, but I will also talk a little bit about that a little bit later in the presentation. And again, this strengthens our portfolio and also strengthens our position in our core areas as we are optimizing the portfolio continuously. On our development projects, we have mentioned this in the past, and our CAPEX is, well, spent one third on infill drilling on our existing assets, which is a very good investment. And then the remaining is mostly used on the Draugen Power from Shore project, which is still continuing. We did have a successful cable installation that goes from onshore to the platform in Q4, and we are now ready to also start installing equipment offshore during 2025 on the Draugen platform. So those are very important milestones for us. It reduces the emissions by 95% when we do have the field electrified in 2028, but it also, as I've said in the past, is a very important cornerstone for us when it comes to future value creation in the area until 2040, but also beyond. The remaining CAPEX is used on Bestla. Bestla is on track, and it's also on budget with the same people and the same contractors that successfully developed the Hasselmus project to Draugen, which is again 24 million barrels of oil equivalent, which will then start early in 2027. And this will then add 10,000 barrels net to OKEA when it's put on stream. So the strategy of developing resources, creating more reserves in and around our asset hubs is paying off, and Bestla is an extremely good example for that. And exploration, as I just mentioned, inorganic growth has been part of the strategy for OKEA for quite some time, and I think we have also delivered successfully on it. 16,000 barrels we had when we launched the strategy. We are guiding or achieving 39,000 this year, but also organic growth is very important for us. Now we have production, we have good cash flows, but also organic growth for the long-term development OKEA on the Norwegian Continental Shelf is very important for us. Therefore, I'm very happy to show a slide like this with firm wells. We are in the middle of a very exciting exploration period right now. I mentioned Prins, which we are drilling now from the Brage platform. We are drilling currently at Mistral and expect results there in Q1 2025. Horatio will be also initiated drilling on now in Q1 in February, actually, in the Gjøa area for the Horatio well. And then Arkenstone. Arkenstone was drilled in Q4 in December last year, but we hit some shallow gas around 420 meters below the bottom of the sea. So we had to cease the operation. We had to redesign the well, and the operator, Equinor, was now working very hard to actually get it into the drilling plan again in 2025, but then with a different well design, so we are able to go through that shallow gas. So Arkenstone will still be drilled and is coming. And last and but not least, two of the licenses we were awarded in the APA rounds now, it's Fagn and also K2. Fagn is a very interesting area. It's very close to the Linorm prospect, and K2 is also a very promising area that we want to explore. So these two are very important contributors to us. So again, being very focused on inorganic growth, we have also now paved the way and established a very good organic growth opportunity for the company for the years to come. So with that, I will get back with a summary after Birte has taken you through the financial section. So with that, I hand over to you, Birte. Thank you, Svein. The financial statements for the fourth quarter do not fully reflect the strong operational results outlined by Svein. This is due to a significant underlift, which will be recovered in the coming quarter. Despite otherwise normalized financial statements without any impairments and only limited effects of the Yme divestment, the weakened kroner against the dollar results in a currency loss, which reduces net profit after tax and also the net debt position. However, the loss is unrealized and does not have any cash impact. But let's dig into the details, starting with production and sales as usual. Production performance remained strong and resulted in 37,800 barrels of oil equivalents produced per day. This includes the two months of Yme production prior to closing of the sale transaction at the end of November. The production optimization initiatives at Draugen were more successful than anticipated and contributed with an additional 1,300 barrels per day in the quarter. We sold 29,200 barrels of oil equivalents per day. The lower volume sold compared to the volume produced was a result of the underlift equivalent to about 8,400 barrels per day. This was mainly due to no liftings of crude from Draugen and Brage during the quarter. As mentioned, this is expected to be recovered in the first quarter of 2025. The average realized crude price was $76.7. 18% of the volume sold were NGLs, which are trading at a discount to crude and results in an average realized liquids price of $69.2. Market prices for gas increased significantly during the quarter. The average realized price of gas amounted to $80, and in the previous quarter, $10.4 of the realized gas price related to gain on hedging. In the current quarter, the realized price includes a hedging loss equivalent to $0.20 per barrel. This resulted in a total petroleum revenue of $2,183 million. The graph to the left illustrates our crude liftings over the last five quarters, as well as the average observable market price. This shows a relatively stable oil price in recent quarters. The lower lifted volume was mainly due to the underlift described earlier, and as illustrated by the gray bar to the right, this will be recovered in the coming quarter. The graph to the far right outlines the difference between the average market price of Brent for the quarter of $74.7 compared to the average realized liquids price for OKEA. A positive quality difference equivalent to $1.8 brought the realized crude price above the market average and amounted to $76.7. With a high volume of NGLs sold in the quarter, the average liquids price ended at $69.2. Here we illustrate the volumes of gas sold over the last five quarters and the observable average market prices for NBP in the same period. In contrast to the relatively stable oil price, the gas price has been on an upward trend throughout 2024 and nearly doubled since the start of the year. The increase in gas production from Draugen contributes to a significantly higher volume compared to the two recent quarters, and this comes at a very welcome time with a strong gas market. Now over to the profit and loss statement. We deliver operating income of $2,262 million, consisting of the petroleum revenue of $2,183 million and other operating income of $79 million. The other operating income comprises net tariff income at Gjøa and Statfjord of $48 million and a gain of $49 million related to the closing of the Yme divestment. The gain on Yme mainly relates to currency updates. Production expense amounted to $805 million or NOK 217 per barrel. Exploration, general and administrative expenses of $178 million comprise SG&A expense of $31 million and exploration expense of $146 million. The high exploration expense was mainly due to purchase of seismic of $112 million. Net financial expense amounted to $262 million and mainly relates to a net currency loss of $225 million and net expensed interest of $35 million. The currency loss is unrealized and mainly relates to the $2 nominated bonds as the Norwegian kroner has weakened by 8% against the dollar during the quarter. Tax expense amounted to $634 million, which brings the net profit to $68 million. The effective tax rate of 90% was higher than the expected 78% due to financial expenses only being tax deductible at the corporate tax rate of 22%. Moving on to the balance sheet. Goodwill amounted to $1.6 billion and comprised $1,450 million in technical goodwill and $163 million in ordinary goodwill. Cash and cash equivalents amounted to $3.3 billion. In addition to the cash balance, $254 million in excess liquidity has been placed in money market funds classified as other assets. Interest-bearing bond loans of $2.8 billion comprise the OKEA04 and OKEA05 bonds equivalent to $250 million. The increase relates to the unrealized currency loss. Income tax payable of $1.6 billion represents remaining tax payable for 2024. Asset retirement obligations of $9.5 billion is partly offset by asset retirement receivables from Shell, Equinor and Harbour Energy of $4.6 billion in total. As for the cash development, cash generated from operations was $1.5 billion. Taxes paid of $674 million includes two tax installments for 2024. Of the $905 million used in investment activities, $799 million relates to investments in the Draugen Power from Shore project, the Bestla development and production drilling and Brage and Statfjord. In addition, exploration expenditure of $106 million relates to the exploration wells Mistral, Prins, and Arkenstone. The cash used in business development consists of the net settlement of the Yme transaction of $197 million and $10 million in contingent consideration paid to Harbour Energy. This brings the total liquidity to just an excess of $3.5 billion, of which $254 million is placed in money market funds. To end the financial review, I will provide a recap on our guidance as well as some other updates. As Svein has already mentioned, for 2024, the full year production, including Yme, ended at 39,100 barrels per day and slightly above the guided range of 37,000 to 39,000. Excluding Yme, the production amounted to 36,000. As for investments, total CAPEX for the full year ended at NOK 3.1 billion, just below the guided range of NOK 3.2-NOK 3.5 billion. Excluding Yme, we end at NOK 3 billion. Our guidance for 2025 and 2026 remains unchanged, and we expect to produce between 28,000 and 32,000 barrels per day in 2025 and between 26,000 and 30,000 barrels per day in 2026. We expect to invest between NOK 3.2-NOK 3.7 billion in 2025 and between NOK 3.2-NOK 3.8 billion in 2026. And as highlighted during the third quarter update when we first provided guidance for the coming two years, CAPEX estimates are based on both sanctioned projects and potential upsides that we believe will be matured and developed. This also means that timing on some of these projects is uncertain. I would also like to remind you that it usually takes some time from development to production in our industry, and we expect that the majority of production contribution of these investments in 2025 and 2026 will come after the guided period. Bestla is a good example of this dynamic and will contribute with 10,000 barrels per day net to OKEA from 2027. As a final note, we intend to change presentation currency to US dollars from and including the first quarter of 2025. The functional currency will remain Norwegian kroner, but all numbers will be translated and presented in US dollars. That's all from me for now, and I'll give the word back to you, Svein, for some closing remarks. Thank you. Thank you very much, Birte. In summary then for Q4 for last year, continued strong production performance on our asset, also very stable performance on our partner-operated assets, which we're happy to see. We are realizing value through our portfolio optimization. So the sale of Yme as a non-core area for us has also brought in value creation. We have a healthy cash position as a company, and our development projects are developing and progressing well. As you could see on our exploration slide, we do have an ambition to drill up to four exploration wells per year. That doesn't mean we have to drill four exploration wells per year. This is quality wells that we are continuously maturing. But anyway, this is a threshold we think is suitable for a company of our size. We are building and maturing a portfolio of investment opportunities, both organically but also through our organic projects that we are developing in the company. So with that, again, a very good quarter for OKEA. We are doing what we, I hope, have told that we are going to do. So production is very important for us. And with that, we will then have a Q&A session, and I will also then be joined by Birte again, and hopefully we will be able to answer the questions you may have. Thank you very much. The question and answer session. If you do wish to ask a question, please press five star on your telephone keypad. To withdraw a question, you may do so by pressing five star again. There will be a brief pause while questions are being registered. The first question will be from the line of Roald Hartvigsen from Clarksons Securities. Please go ahead. Your line is now unmuted. Morning, Birte. Congratulations on another strong quarter production-wise. I guess we first have to touch upon returns of capital to shareholders. So you now have a meaningfully positive net income for about 12 months, which I guess has previously been a restriction on distribution. Then with that net income, you're now on track. Is there any other distribution restrictions limiting the dividend payments at the moment? And beyond that, are there any specific milestones you want to see achieved before potentially making any announcements with regards to capital returns to shareholders? Or is it more likely you take the full picture into account when assessing this? Thanks. Thank you, Roald. I think we need to just reiterate what we have said before. Our capital allocation principles remain, which I remind is a healthy balance sheet, and then to balance growth and direct distributions to shareholders. As I also said in the third quarter reporting, dividend is important and a priority for the board. At the moment, we are in a very capital-intensive period. We are early in the phase of the two big projects, Power from Shore and Bestla. So this is something that we will revert to when the board considers that we are in a position to pay dividends again. You are correct to point out that we currently have a dividend capacity according to our bond definitions of just shy of NOK 200 million. The market is quite solid at the moment. So when the projects are progressing and we see that the budgets are in line, if the strong market continues, I think that's two of the criteria that could result in a new dividend plan for OKEA. But at the moment, we do not have a dividend plan, and we will revert when we are in a position to pay dividends again. Thanks a lot. And then I guess this one goes to you, Svein. One of the key reasons stated for the strong production in the fourth quarter was production optimization initiatives at Draugen, which resulted in significant ramp up gas export. Should we expect these production optimization initiatives to also sort of continue to extend with strong gas exports into 2025, or do you view this more as a short-term boost for production? Yeah, no, thank you for that question, Roald. The improvements we did, some of it was facility-based last year on Draugen, but also increasing the production and monitoring the reservoir performance is also important because to avoid what you are saying there, this is something that will be long-term and needs to be long-term. We are not optimizing and maximizing production, which will have a long-term negative effect. The positive thing, though, with the Hasselmus delivery is that the increased performance we saw last year has continued and is still continuing. So we can expect that that plateau we have reached now when it comes to Hasselmus is something we are planning for also in the period that comes. Obviously, we will alter it if something changes, but what we saw in Q4 is something which has sustained into Q1. Thank you. That's it from my side today. Thank you, Roald. Thank you. The next question will be from the line of Teodor Sveen-Nilsen from SpareBank 1 Markets. Please go ahead. You'll now be unmuted. Thank you. Good morning, Birte. And Ryan, thanks for taking my questions. A few questions for me. First, on your overall strategy, is it fair to assume that you focus slightly more on exploration now than in organic growth compared to what you have communicated previously? And the color around that would be useful. Next question there is on hedging. Are you tempted to hedge more gas at the current gas forward and spot price? And last question on dividend resuming. Should we expect no dividends for 2026 as well since 2026 also will be a pretty CapEx-intense year? Are you dividend for 2026, sorry, dividend for 2025 but paid in 2026? So any thoughts around that would be useful. Thank you. Yeah, thanks for the questions, Teodor. I can take the first one on strategy. We are not changing the strategy as such. I will just say we are maturing the strategy. When we launched this in 2021, we had 16,000 barrels of oil equivalents in production. We achieved 39,001 last year. So I would say we have definitely achieved on our growth target. But that is also production that we prioritized because that gave us early cash flows. And those cash flows could also then contribute to the organic development that we are currently trying to strengthen. And also when it comes to organic opportunities, as you could see in the presentation now, we have a healthy exploration portfolio. Some of it is ongoing right now. And the reason why there has been like two or three years as well is that we have worked very hard to kind of optimize and high-grade our exploration portfolio. So when we actually move into organic growth, we have developed these targets and these are the targets we really believe in. And this is just a natural kind of maturation of the company. If you're going to maximize the Norwegian model, to put it that way, we need to be a fully fledged both exploration and production company. And this is just one of the stepping stones to also be a significant company for the long term on the Norwegian Continental Shelf. And maybe I can take the last two ones. So more hedging if I'm tempted. The answer, I guess, is yes. When we see prices in excess of $80 a barrel equivalent on gas, we are continuously working on our hedging efforts to at least lock in parts of our future production on those levels. As for your third question, should we expect dividend to be paid in 2026? I think I need to revert to my initial questions. We will revert with a plan once we consider us to be in a position to pay dividends. Obviously, by 2026, the project will have progressed further and we will have better visibility into the CapEx budgets. But beyond that, we do not comment on future dividends. Okay, thank you. That is fair. Just one more question here on the exploration. You said, Svein, that the exploration is an important part to maximize NCS model. I definitely agree on that one. But could you comment on the commercial threshold for the Arkenstone and Horatio prospects? Well, currently, first, we need to find something there. So our focus so far has been to kind of find these, see what's in the ground, basically. The Arkenstone in particular is a play opener. There is no existing infrastructure in the area, but it's an extremely exciting well when it comes to potential volumes in the area. So being part of the Arkenstone now in 25 together with the operator Equinor and also Aker BP is something we are really looking forward to. But when it comes to kind of thresholds of commerciality, etc., that is something we need to get back to once we have established what we have in the ground. Okay, thank you. As a reminder, please press five star to ask a question. The next question will be from the line of John Olaisen from ABG. Please go ahead. Your line will be unmuted. Yeah, good morning, ladies and gentlemen. A couple of questions. Let me first start with a question for preliminary guidance on exploration spending for 2025. How much do you expect to spend on exploration in 2025, please? Oh, thank you, John. Well, on average, we estimate that a well-net to OKEA cost is about 150 on average. Obviously, that depends on your working interest. But I think that's a fair estimate for exploration spend. And as you have seen the slide with the targets that we have, we currently have four wells targeted for 2025. Svein, on Arkenstone. May I also just mark a housekeeping question? You mentioned that you expect the Q4 underlift to be fully reverted in. Did you say Q1 2025 or during 2025? Sorry. No, Q1 2025. The Brage lifting has already taken place and the Draugen lifting is expected in early February. Right. So in Q1, we should expect an overlift of similar size as underlift in Q4. Yes. And we have indicated the expected liftings in a separate slide in the presentation, Jon. Yeah. Very good. And then on the M&A side, do you see any assets or companies that potentially could be that you're looking at at the moment for potential M&A on non-organic growth for 25? Yeah, well, it's hard to be specific, obviously, on that one, but I believe there are still opportunities on the Norwegian Continental Shelf. There has been quite a bit of swapping, strategic swapping maybe between licenses, which we also took part in last year on the Mistral Horatio exploration licenses. But there is still, I believe, opportunities that kind of fit our strategy. But importantly for us is that we are identifying what actually can suit our portfolio, that we do see additional value creation and that it actually has the right price, obviously, which is important to us. But we still believe there are M&A opportunities and we are working continuously on that, obviously. But it's also one of the areas where it's very hard to be specific, as you may understand. Yeah, I really understand. Are you looking at particular deals as we speak? Not to be specific on which deal or if there's any, but just wondering in general, are you? We never have an empty hopper. Are Are we in discussions right now or not? We never have an empty hopper when it comes to BD and inorganic growth, to put it that way. Yep. And then follow up on Arkenstone. When should we expect the well to be studied again? That is also a good question. The redesign is currently ongoing. The initial discussions we had with redesign of the well, the discussions we had in the license indicated that it could be during the first half of 2025, but that is something we need to get back to. Obviously, the operator Equinor has quite a few rigs which are moving around doing drilling operations. So optimization and where we can actually slot it in in the most effective manner is something that the operator together with us and Aker BP is looking at. But I need to get back to explicitly when that is expected. Fair enough. Thank you very much for taking my questions. Have a nice day. Bye-bye. Thank you, John. Thank you. As no one else has lined up for questions in this call, I'll now hand it back to the speakers for any closing remarks. We do have some questions online that we might run through first. We have a question from John Erik Rørheim, who says that given the current market conditions and the company's financial position, can you outline the path to reinstating dividends? What key financial or operational milestones need to be met before you consider resuming distributions to shareholders? I think we have already answered that in an earlier question. Moving on to the next one from Karl Kangö, who has a few questions. Hi. Given that OKEA's ambition is to deliver value-accretive growth, which metrics should shareholders follow to see how OKEA is progressing on that ambition? I think that it's really up to the various shareholders, but I think obviously dividends combined with share price development is an obvious combination of metrics and then look at the growth, production, and cost structures. He also asks, have you considered adding capital efficiency metrics to give shareholders an insight into the return profile? With With large CapEx and M&A deals, how should shareholders evaluate capital efficiency? Again, I think that's up to individual shareholders. I can say that we have obviously some metrics looking at our capital efficiencies, but it's not something that we disclose to the market. We do provide some of the break-even prices, for example, as we have for Bestla, to give some indication on the profitability of that project. He asks, do you have an internal return on invested capital goal when deciding on investments in M&A? Can you share what returns you're aiming for? Again, yes, obviously we have some internal return requirements, but it's not something that we disclose to the market. Obviously, that also has some competition reasons for not doing that. How should shareholders think about the success of the latest Statfjord acquisition? Which metrics do you use internally to evaluate the success of historic deals? It's not a surprise that it's not gone exactly how we expected on Statfjord, and that has also resulted in impairments in some of the quarters in 2024. Metrics we use internally, we use the traditional metrics. We look at the cash flows, we look at the net present values, we look at the potential upsides that we can realize going forward, and other traditional metrics that we use. Do you consider any projects outside of Norway? That's That's Karl Kangö's last question. The answer to that is that we do not consider projects outside of Norway. We are focused on the NCS. Then Jan Egeland asks, OKEA remains one of the few oil and gas production companies that doesn't pay a dividend. I couldn't see any mention of it starting up now that you are in a position to do it, and investor remains in the dark on this. Could you elaborate on when you expect it to start up? And I think we have answered that earlier. I see that you have pre-sold very small volumes of gas in 2025 and instead hedged with bigger puts and calls. Can we expect this to be the strategy going forward, or are you intending to increase presale now that prices are high? We continuously evaluate our hedging strategy in view of the market, and I think you are onto something here. It's quite possible that we will increase the presales and maybe in combination with some puts and calls, which means that typically you have no cost on those positions. Can you give a little detail on when the Draugen lifting will be done this quarter and the size of it? We have provided details on the timing, which is early February. The size of it, I guess I can say that of the projected total liftings for the coming quarter, the Draugen lifting is about a third of it. Russell Searancke asks, there are some market concerns about the absence of FIDs in Norway, apart from your Bestla in brackets. What is OKEA's outlook? How many new projects are you maturing, and when will the Ofelia Kyrre project move into FEED? Yeah, I guess on that one, there are concerns about FIDs in Norway, but there is also an increased activity level now when it comes to exploration, something we also can see on the licenses awarded. So the projects on the Norwegian Continental Shelf will continue, but we did have quite an increased activity following the pandemic, obviously. When it comes to us, what we are looking into is near-field exploration and also activities like the Bestla on Brage. We are currently drilling a producer, which is the Kim discovery. We had a year and a half ago of 2.9 million recoverable BOE, and we are actively working around the hubs where we are. We also have some prospects, Hasselmus, around Draugen that we are also trying to develop in the future. In addition then, of course, to the results of the organic exploration portfolio we are seeing now, which then will come further down the line. When it comes to the Ofelia Kyrre project, we are not in those, but we are obviously in the Gjøa Nord area with our previous Hamlet discovery. So those are some of the prospects which are now being matured, both in the licenses, but also to see can it jointly be developed. And that is something that is progressing now. But when we are moving it into FEED, that depends on the concept evaluations that are being looked into now on all the licenses. And then Russell also asks, what sort of pressure are you seeing in the oil field services sector that might affect your schedules and cost? Well, we are seeing some pressure when it comes to those services, but not something which is not manageable. We do see some cost increase, which was expected because of the higher activity. But from an OKEA point of view, we are still on budget and schedule when it comes to Bestla. We have placed all the orders there. And when it comes to the future as well, I think we will see a gradual decrease in the pressure again once we have these large projects in Norway delivered. We've had Castberg and Aker BP has the Yggdrasil project, etc., which is in the pipeline now. So I think we will see a cooling down a year and a year and a half from now. But when it comes to OKEA now, we do not see any direct impact on our Bestla. We do see some increased pressure on cost and also capacity on people when it comes to the Power from Shore project, but not something we can't manage together with our contractors. And then Erik Borten has a question. He says, "Hi, congrats on a great 2024 with strong European gas prices, both in spot and futures markets for 2025. Are you taking any steps to put on more hedges to lock in these attractive prices?" And the answer to that is yes. We are continuously working on our hedging strategy and locking in positions at attractive prices. And then Fredrik Bredal-Kramer asks, "When could we expect volumes from a potential discovery from Arkenstone, Prins, Mistral, or Horatio?" Yeah, those are quite different prospects. If we do have a discovery in Arkenstone, that is an area with no infrastructure. So then you have to develop the infrastructure. So that is quite some time away. When it comes to discoveries, which is commercial that you find in what we call catchment areas around assets from a discovery to actual production, I would say that normally it takes around four to five years, well, depending on how complex it is, but three, four, five years from a discovery until you actually have it in production is the normal kind of timeline. But that is obviously very dependent on reservoir, what wells you need to drill, and how technical it actually is. But you should have a five-year horizon when it comes to discoveries. Then Peter Billing asks, he has two questions. Will you provide restated figures in dollars for 2023 and 2024, both annual and quarterly ahead of the Q1 2025 report? We did not intend to do that. This is not a functional currency change. It is a presentation currency. It's to look at the balance sheet exchange rates. For the balance sheet, it's closing exchange rates. For the P&L, it is average exchange rate. It shouldn't really have a big impact. It's just a translation of previously reported numbers. We will obviously do so in relation to the Q1 reports. Then he asks, could you provide an overview of the percentage depletion on your key assets? We do not provide an overview of that. Remember, what we do every day is to fight depletion. We have initiatives, if not every day, ongoing all the time to fight depletion. We do that through production optimization as we have done on Draugen, and we do it through drilling as we, for example, do on Brage and Statfjord. What I can add is that depletion rates also vary quite significantly across our portfolio. So whereas, for example, Draugen has just a couple of percentages depletion a year. Or without any new volumes there, depletion is in, well, 20-30%. So quite a big difference between different assets. Yeah, and as Birte mentioned there as well, this is what we are working on every day to fight that decline. So worth noting there as well on Brage, last year we had a reserve replacement rate of 161%. So that is what we are doing every day on our assets to actually fight that depletion. And then Håkon Lunde asks, the Arkenstone well in the Norwegian Sea that was abandoned due to shallow gas, do you have a plan to drill that later this year? And I will. The answer there is yes. Redesign of the well is ongoing so we can actually drill through the shallow gas that we saw. And then we are aiming to get it into the drill string during 2025. And as I mentioned to John Olaisen as well, we have to get back to the exact timing of it, but that is the priority of all partners in the license. And then David Mirzajani asks, how do you see your liquidity being impacted by steady CapEx and falling production revenues ahead of Bestla coming on stream in 2027? Yes, we are, as also this quarter, our cash position is reducing, but this is also why we went to the bond market and financed the Bestla development last year. So we have a solid cash and liquidity position to manage that. And as of course you are aware, we also have now quite a strong market which is supporting our cash inflows from operations. So I think that's all we have now from online questions. And then I think I'll just thank you all for your attendance and looking forward to see you in the next quarter reporting. Absolutely. Thank you very much. And if you should have any questions after this Q&A as well, we are available if you need any further clarifications. Thank you very much. Thank you.