Good morning and welcome to the OKEA third quarter presentation. My name is Svein Liknes, I'm the CEO of OKEA, and I'm also joined by Birte Norheim, our CFO, who will take you through the finance part a little bit later before I come back and take the summary. But before we dive into that, I would like to take you through an operations update and also some general considerations of the quarter at large. So the highlights in the third quarter are that we have seen very strong operational performance on all our assets in our portfolio. Even though we've had planned maintenance on most of them as well, we have been able to maintain strong production of 37,300 per day in bpd in production, which is just slightly below the previous quarter. We have also done production optimization initiatives on Draugen, on the Hasselmus field. Hasselmus was started back in October last year and was a field that was going to deliver 4,400 bbl equivalent, and then we increased it to 4,000 bbl and then we have done even more de-bottlenecking now, so now we have even more and stronger production from the Hasselmus development started October this year, and we've had no serious incident during the quarter. We had an incident last week where we had a radar beam that fell down on Brage, but obviously we will report more on that. There were no injuries associated with that incident, but we've had no serious incident in the previous quarter. We have also improved our financial performance, both on the revenue, but also EBITDA has improved. We do see a net impairment income of NOK 871 million, which is driven by the sale of Yme, and the Yme sale is something I will get back to a little bit later. We also then see the results of this as increased net profit after tax and also strong net liquidity position for the company. Birte will go into more of the numbers later on. Overall, on the portfolio, we have sold the Yme asset, our 15% working interest in Yme. We have been part of Yme since 2016, but it's a non-core asset in our portfolio, so we decided now to divest it to a total consideration of $15.65 million. We have also, during a process we've gone through now in association with the RNB numbers, we see higher energy content in the Hasselmus gas, which increases the reserves at Draugen and Hasselmus combined by 2.1 MMbbl of oil equivalent net to OKEA, which is also a very positive development in the Draugen area. On our development projects, the Bestla is progressing according to plan, which is to tie back to Brage that I will get back to a little bit in a short time as well. And we also have the power cable to Draugen. Once we finally started the construction work onshore for the cable and the power from shore to Draugen, we have made very good progress onshore, so that is now ready for the cable installation, and we expect the cable to be completed by year-end. We also see more complexity when it comes to the offshore work on the power from shore project, and we are now doing a rebaselining together with the main contractor, Aker, to see what impact this will have, and we have then pushed back the startup of the electrification from 2027- 2028, but that rebaselining is still ongoing, and we will get back to more details on that on a later stage, so the key operational figures for the quarter: safety, as I mentioned, 0.6 in serious incident frequency, so that is very stable, which is good. Production, as I mentioned, 37,300 on average for the quarter, which is just a slight drop from the previous quarter, even though we had quite a bit of maintenance, planned maintenance executed on our assets. Production efficiency is down by 2%, and that is also predominantly driven by the planned maintenance that we've had in the period and also impacted by Kårstø, which is our gas evacuation route for most of our assets that also had a 23-day shutdown, which impacts our production efficiency because we can't produce and export as much as we used to, and the production expense is very flat, so we maintain our cost focus, and we can still see that we have control over the cost expenses on production. The thing to note on this schedule is we see the very good growth in production volumes since the third quarter of 2023, and also what you can see here on the last one for the third quarter of this year is that you can see the increase in volumes from Statfjord. We have been working very hard together with the operator and the license group on Statfjord to improve performance, and we start seeing results, and that is something you can see on this slide here. On the bottom of the right-hand column, you can see the Draugen volumes have decreased in the quarter, and that is because of the ESD test that we did, the optimization on the gas train that we did for Hasselmus, but also the export route of Kårstø that was shut down for 23 days, which impacted obviously the production from Draugen. Production efficiency that you can see in the bottom are still very high, and the numbers are affected by planned maintenance and also, as I just mentioned, the Kårstø shutdown. Besides that, everything is due to planned maintenance. On the right-hand side, the Statfjord area, one of the main focus areas for us there is to increase production efficiency, and I'm glad to see that we are now registering production efficiency above 90%, which is very good for that asset. A quick run-through on operational update on our assets. Draugen, we've had planned maintenance shutdown on the Kårstø that impacted production, as I have mentioned. We have optimized the gas processing facility, and we have increased then the throughput from Hasselmus on gas production on Draugen. We have increased the reserves by 2.1 MMbbl of oil equivalent net to OKEA, which is then due to most likely the higher energy content and the Hasselmus gas. On Brage, again, also affected by the Kårstø shutdown, the Fensfjord North well has been completed and is ready for startup now in Q4. In November, actually, we will start that up. That is a well that we have drilled and spent quite some time on during the summer, but that is now completed. Now we are waiting for some equipment downhole to swell, and we can then start production from that well. We are also exploring in the Brage area in the Prins Prospects, and we are also then drilling a producer in what we call the Sognefjord East area. We did a discovery that we called the Kim discovery in this area last year and has 2.9 MMbbl of recoverable volumes, and that is the producer we are now going to drill, and in association with drilling that producer, we are also doing pilot exploration wells like we have done in the past, and we believe the Sognefjord East area could be a very exciting area for the future. On Statfjord. As I have mentioned, we have increased the production performance, we have increased production efficiency, and we have also now approved in the license what we call FLX 2.0, which is an updated drilling program which will then have a more robust reservoir drainage strategy. So obviously that takes time to drill those wells, but that is what we will see deliver the volumes from Statfjord in the past. So I'm glad to see that we are seeing improvement in the Statfjord area in line with our commitment when we closed the deal last year. Ivar Aasen, very reliable operations from Ivar Aasen. The main thing there is that we are maturing the increased oil recovery drilling campaign in 2026 together with the license group. On Gjøa and Nova, we have had some issues with on the water injection and pressure support on the Nova, but that has now been restarted. We still see some integrity issues on the water injection plant, but that is something we are assessing now and will change out in the future. We also have a rig to drill the fourth water injector at Nova to give even more pressure support so we can maintain the production volumes that is coming from Nova. And the Gjøa area is still very important for us, even though we just have a 12% ownership stake in Gjøa. It is a very interesting area to actually be in, and we see several tie-in candidates, which is now approaching the Gjøa as a potential host for future developments. On Yme, as I have already mentioned, we have entered into an agreement with Lime Petroleum to sell our 15% working interest stake for a consideration of $15.65 million, which we expect to be closed and completed by Q4 this year with an effective date of 1st of January 2024. Talking about Yme then, as I have mentioned, we entered Yme in 2016. We have been part of sometimes a very challenging development project, and we have also, I believe, been a very prudent partner to the operator to get Yme in production and stable operations. But this is also the time for us, as we are growing as a company, to do portfolio optimization. Because Yme is not in our core area with those 15%, we then wanted to exit, and we managed to get a fixed consideration which exceeds our holding value. So with this sale, because of the effective date 1st of January, we are reducing the 2024 production by around 3,000 bbl of oil equivalent per day because we are then doing the closing before year-end. And we are also reducing the CapEx by NOK 140 million. But most importantly, we are freeing up resources, also human resources, to focus on other core areas where we want to grow and see more value creation in the future. And the main accounting implications under the agreed terms is that we do see a reversal of previous impairments of almost NOK 1.2 billion in this transaction. Development projects w e have the Draugen power from shore, and I will just repeat again, we are going through a rebaselining there, so we are moving now the startup of the electrification from 27- 28. But we are doing this because this is an important strategic pillar as well for Draugen for the long-term operations. We now have a production license on Draugen till 2040 and beyond. So this is something we still want to do, but we have to rebaseline, especially the offshore work. But the cable work is progressing well, and that is something that we are completing this year. And this will, as I mentioned before as well, reduce the CO2 emissions from Draugen by 95% when it's put into operation. Bestla, which is another big project that we have, which is the tie-back to Brage, 24 MMbbl of oil equivalent, which will then add 10,000 in 2027, 10,000 bbl of oil per day to net to OKEA when it's in production, which is an important contribution in our production portfolio going forward, as obviously we are in a declining business. I'm also very happy to see that we managed to develop this project with a break-even of $40 per BOE. This is also some of the future for Norway to tie in these smaller tie-backs into existing host facilities. That one will start then in 2027. I also wanted to add a slide which we have not been displaying previously as much as the exploration activities. Obviously, building a portfolio is important for us. We have successfully, I would say, built a portfolio of producing assets, which has taken our production from 16,000 when we launched the strategy up to closer to 40,000 bpd. Exploration and organic growth is important for us, predominantly around our hubs. The exploration activities that we have in front of us now as a company is that we do have the Prins that I just mentioned, which we will drill from the existing rig that sits on Brage into the Sognefjord East. That is a well that we are drilling and spudding now in Q4. We are also entering the Arkenstone in Q4. I believe the estimated spud date there now is in the end of November, 26th, I believe it is now. And then we are doing the Arkenstone, which is in the northern area of the Norwegian Sea with operator Equinor, which is an area that could open up a play, which is very exciting. And then we're also doing the Mistral well, which will be drilled straight after Arkenstone with the same drilling rig, also with Equinor as operator, which is also a very interesting area that we look forward to learning more about and also hopefully have some discoveries there. And our ambition going forward, because we have now established stable production and also steady income in the company, is to also focus on the organic growth opportunities, which we still believe sits on the Norwegian Continental Shelf, which then makes us a full-fledged E&P company. So that's why we wanted to mention this slide as well. Then I will get back to the summary slides afterwards, but before we get to that point, then Birte will take you through the finance section. Thank you, Svein. The financial statements for the third quarter are characterized by the strong operational results outlined by Svein, including the improved production from Statfjord which offsets the impact of the planned maintenance at Kårstø. In addition, a large overlift increases revenues in the quarter. The financial statements are also characterized by several accounting implications relating to the sale of Yme. As Svein also mentioned, the agreed terms of the sale triggers a reversal of previous impairments of NOK 1.185 billion, with a post-tax effect of NOK 261 million. All assets and liabilities relating to Yme have been reclassified to held for sale and represent a strengthening of the balance sheet as interest-bearing liabilities of NOK 454 million and removal obligations of NOK 483 million will follow the sale. I will get further back to the details of this as we go through the financial figures for the quarter. So let's start with the production and sales as usual. We produce 37,300 bbl of oil equivalents per day. Solid operational performance and increased production from the Statfjord area offset the volume impact from the planned maintenance at export pipelines and processing plants. The maintenance at Kårstø lasted for 23 days and was completed in September. We sold 40,800 bbl of oil equivalents per day. The higher volume sold was a result of a total overlift equivalent to about 3,500 bpd, mainly relating to Brage. The average realized liquids price was $74.9. This is somewhat lower than the previous quarter, mainly due to a high NGL discount, which I will come back to in more detail. Market prices for gas increased somewhat during the quarter, and the average realized price amounted to $68.9 and includes a gain equivalent to $10.4 from fixed price hedging contracts. The graph to the left illustrates OKEA liftings of crude over the last five quarters, as well as the average market price marked by the red dots. The higher lifted volume was mainly due to the overlift described earlier. In the coming quarter, we expect a significant underlift. This is mainly due to no planned OKEA liftings from Draugen in the fourth quarter. The underlift will be recovered early in 2025. The graph to the right outlines the difference between the average market price of Brent for the quarter of $80.2 compared to the average realized liquids price for OKEA. OKEA's realized crude price was $81.4 per bbl. However, a high quantity of NGL was sold in the quarter, which traded at a discount to crude. This resulted in an NGL discount of $6.6 and brings the average realized liquids price down to $74.9. On this graph, we illustrate the volumes of gas sold over the last five quarters and the observable average market prices for NBP in the same period, again represented by the red dots. The decrease in gas production from Draugen and Brage was due to the maintenance shutdown at Kårstø and was offset by an increase in production from the Statfjord area as well as from Gjøa and Nova. So over to the profit and loss statement. We deliver operating income of NOK 2.926 billion, consisting of the petroleum revenue of NOK 2.944 billion and other operating loss of NOK 18 million. Other operating loss was mainly driven by an increase in the fair value of contingent considerations of NOK 22 million following an increase in forward prices for gas. Production expenses amounted to NOK 790 million, equivalent to NOK 233 per bbl. We recognize an impairment income of NOK 871 million. As mentioned, NOK 1.185 billion relates to a reversal of previous impairments at Yme, following from the agreed terms of the sale. The reversal was partly offset by technical goodwill impairments of Statfjord and Ivar Aasen by NOK 294 million and NOK 21 million, respectively. The technical goodwill impairments were mainly a result of lower forward prices for crude oil at balance sheet date. As a reminder, given that both Statfjord and Ivar Aasen are now carried at fair value, any adverse changes in macro conditions or asset performance will result in further impairments of technical goodwill going forward. Exploration and operating expense of NOK 75 million comprises SG&A expense of NOK 33 million and exploration expense of NOK 42 million. Net financial income amounted to NOK 28 million and mainly relates to a net currency gain of NOK 86 million, partly offset by net financial expense of NOK 58 million. Tax expense amounted to NOK 1.889 billion, which brings the net profit to NOK 277 million. The effective tax rate of 87% was higher than the expected 78%, mainly due to impairment of technical goodwill not being tax deductible. Moving on to the balance sheet, goodwill amounted to NOK 1.6 billion, of which NOK 342 million relates to remaining technical goodwill at Statfjord and NOK 165 million relates to Ivar Aasen. Cash and cash equivalents amounted to NOK 3.6 billion. In addition to the cash balance, NOK 251 million in excess liquidity was invested in money market funds and were classified as other assets. Interest-bearing bond loans of NOK 2.6 billion comprise the OKEA 04 and 05 bonds. There are no other interest-bearing liabilities remaining this quarter, as the NOK 454 million relating to the financial lease of the Inspirer rig at Yme was reclassified to held for sale. This results in a net liquidity position of about NOK 1.3 billion. Income tax payable of NOK 1.9 billion represents remaining tax payable for 2024. Asset retirement obligations of NOK 9.3 billion is partly offset by asset retirement receivables from Shell, Equinor, and now Harbour Energy of NOK 4.3 billion. NOK 483 million in removal obligations relating to Yme was reclassified to held for sale. Cash generated from operations was a solid NOK 1.8 billion. Taxes paid of NOK 349 million relates to payment of the first tax installment for 2024. The NOK 646 million used in investment activities mainly relate to investments in the Draugen electrification project, Bestla, and production drilling at Brage and the Statfjord area. This brings the total liquidity to just shy of NOK 3.9 billion. As mentioned, NOK 250 million in excess liquidity were placed in money market funds, and we end this quarter with a cash balance just in excess of NOK 3.6 billion. So now moving into forward-looking territory. To provide further insight into how we work to maximize value creation from our portfolio, we are now expanding the guiding horizon to include the next two years. I think it's important to stress that the indicated ranges also include less mature projects, some of which may not materialize within our investment hurdles and also with more flexibility with respect to phasing. This is particularly the case for the longer dated guiding. I should also underline that the guidance is based on our existing portfolio and does not account for M&A activities. Starting with investments. In addition to the large brownfield development projects already sanctioned, Power from Shore and Bestla, we do have a portfolio of attractive investment opportunities with low break-even and short payback. These investment opportunities are important contributors to fight natural decline and to further enhance the robustness of our asset base. We therefore plan to continue to work hard to mature these opportunities towards development. This also means that the investment level in OKEA will be higher in the coming two years than what has been the case in recent past years. On production. Natural decline in both 2025 and 2026 is expected to result in somewhat lower production compared to the current year. Bear in mind that Bestla, which will add 10,000 bpd net to OKEA, is scheduled for completion in 2027 and outside our guidance period. In addition, the majority of the production contribution from projects with investments in 2025 and 2026 falls outside the guidance period and will only come into fruition later. Finally, I will try to wrap up what we have covered in this forward-looking section in a summary. Starting with the current year, we narrow our production guidance from 36,000 bbl-40,000 bbl to 37,000 bbl-39,000 bbl of oil equivalents per day. About 3,000 bpd relates to Yme, which means that we expect to produce between 34,000 bpd and 36,000 bpd, excluding Yme. We also narrow our CapEx guidance somewhat by lowering the high end from NOK 3.6 billion-NOK 3.5 billion, ending at a revised range of NOK 3.2 billion-NOK 3.5 billion. Turning back our attention to CapEx for the next two years, we expect to invest between NOK 3.2 billion and NOK 3.7 billion in 2025 and NOK 3.2 billion and NOK 3.8 billion in 2026. As mentioned, this is based on both sanctioned projects and potential upsides that we believe will be developed, although timing on some of these projects is uncertain. As for production, we expect to produce between 28,000 bpd and 32,000 bpd in 2025 and between 26,000 bpd and 30,000 bpd in 2026. As mentioned, the majority of the production contribution from investments in 2025 and 2026 comes later than the guidance period, and Bestla is one example of this. I will end on some final comments relating to the outlook. We will pay two tax installments in the fourth quarter, each amounting to NOK 349 million. On the exploration side, as Svein has mentioned, we consider exploration an important element in the long-term value creation potential for the company, and we plan for drilling up to four exploration wells per year with a key focus on our existing hubs. Three exploration wells are now lined up for start of drilling in the fourth quarter. 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, Birte. As a summary then, before we move into the Q&A session, we have seen very strong production during the quarter, even though we've had planned maintenance in the period. We are realizing the value when we are selling the Yme asset. We see strong net liquidity position for the company. We do have good development in our projects, and we are also moving into organic growth. We have three exciting exploration wells that will start now in Q4 and also will be drilled into 2025. And we are continuing to build and mature a portfolio of investment opportunities, both inorganically but also organically for the company. Very happy with the quarter as a whole. Now we are moving into the Q&A session where Birte will join me again, and there is a link on our homepage that will take you there where you can post questions, and there will also be details where you can then call in for questions in the Q&A session. With that, I will thank you for your attention and that you called in, and we would like to see as many as possible of you in the Q&A session now after. Thank you. We'll now start the Q&A session. If you wish to ask a question, please press five star on your telephone keypad. To withdraw your question, you may do so by pressing five star again. There'll be a brief pause while questions are being registered. And we have a question from John Olaisen from ABG. Please go ahead, your line will now be unmuted. Thank you, and thank you for taking my question. A question on slide number 17. In 2026, a large portion of the relatively large portion of the CapEx seems to be related to non-sanctioned projects. Could you elaborate a little bit on which project that that could be, please? Thank you, John. Yes, we can say a little bit about it. Obviously, these are all immature projects or less mature projects, I should say. But there are projects around Draugen, for example, the Springmus project that's included there. There's a lot of not yet sanctioned drilling activities, particularly around Statfjord. To name a few, there's also some projects around the Brage. And we will, of course, come back with more information on those when we are making our investment decisions on those. All right, thank you. And related to the new production drilling strategy at Statfjord. Should we expect that to increase production, or is it just to fight decline on the Statfjord field? Yeah, the extra wells or the new wells that will be drilled on Statfjord is more related to the strategy of draining the reservoir. As we have mentioned in the past as well, is that we need to lower the reservoir pressures on the Statfjord field to get more liberated gas. So we will see increased production from Statfjord by actually producing more water from the aquifer, which is supporting the reservoir. It sounds a bit strange technically, but actually we will see increased production predominantly within gas as we are executing on these wells. Excellent. And my final question before I leave the floor to others. Could you give a little bit of indication about the exploration potential for the Prins project, please? Yeah, we don't have, yeah, the same as we have done in the past. This is just a pilot well, obviously, that we are doing, same as we have been doing in the past as well. Every time we drill a producer on Brage, we use also the opportunity to use the same well bore to do pilots, and we have done so successfully so far. But when it comes to the prospect and what we can expect to find there, we can't kind of quantify anything because we don't guide on it. But we do believe that the Sognefjord East, at least, is an area that is exciting for us, and we want to explore it, and we need to get back to more details as we are progressing. All right. Now that you are increasing the focus on exploration, it would be great if you provide a little bit more on the pre-drilled potential of the targets, similar as Vår and AKBP do. That would be great if you do that at some point. But thank you very much and good luck. Thank you, John. Thank you. The next question will be from the line of Steffen Evjen from DNB Markets. Please go ahead, your line will now be unmuted. Yes, good morning, guys. Two questions from me on Yme. Could you provide some color on the taxes there in the first half of next year? I guess that the tax amount could be lower than what we are now seeing in Q4, at least in light of the divestment. And my second question is on Draugen. Birte, you said liftings will be a lot lower in Q4, predominantly due to Draugen. I see that liftings have been quite stable from Draugen over the past quarters. So would that imply sort of a double lifting from Draugen in Q1 next year? That's for me. Thank you. As for the last question, it could be, but we are not guiding for that yet. But it is just in the early in 2025 that we will get a lifting from Draugen, which would otherwise fall in the fourth quarter. So it's possible, but we don't yet know. There's no significant depletion on Draugen, as you may be aware. So production is quite stable there. Your other question was relating to Yme. On taxes, you are correct. Basically how this works is that when the transaction is closing, it will be a settlement that is the sum of the fixed consideration of $15 million offset by the pre-tax cash flows from Yme until closing date, so from 1st of January until closing date. Then the tax reduction for us will come in the first half of next year. That's correct. But of course, there are many other variables that go into that tax calculation also. Okay, understood. Thanks a lot. Thank you, Steffen. As a reminder, if you wish to ask a question, please press five star on your telephone keypad. As there appears to be no questions on the phone line, I will hand it back to the speakers to handle any written questions. Yeah, first we have six questions from Gunnar Wagle. First one, what is holding you back from confirming the dividend policy for 2025? Second question references the application for Brage and sent to the Ministry of Energy. In the application, a revised permit is requested for increased production beyond 10% of the original permit for the year. If so, any negative impact lower production of Brage in 2025? Third question, is there an expected high decline rate at Draugen in 2025? Four, OKEA has guided that 10 wells-12 wells will be drilled at Statfjord in 2024. How many wells have been drilled so far, and when will they be online? The fifth question, can you say something about production at Statfjord in 2025 and the increase or decrease in production? And the last one, reference to an interview with Finansavisen recently. Both the chairman and the CEO said that the company is prepared for an increase in production. How do you think that the market should interpret such a statement compared to your lower guidance for 2025 and 2026? Well, thank you, Gunnar. I think maybe I can answer the first one and, Svein, the other five questions. As for dividend, our capital allocation principles remain. First and foremost, keeping a solid and healthy balance sheet, and then to balance direct distribution to shareholders and growth. As you also are aware, we are subject to the restrictions under the bond terms, which is basically 50% of the rolling previous four quarters of net profit after tax. Currently, as we have also outlined in more detail this quarter, is that we are in a growth phase. We have two large sanction projects ongoing. We have several attractive drilling targets planned specifically for Draugen and for Brage and for Statfjord. And we have several less mature projects that we see very attractive economics in, with high returns, that we are working on maturing with a target to develop. So I guess I can repeat what we have said before, that dividends remain a priority, and the board intends to revert with a plan once we are in a position to resume a dividend payment. Yes, and I can cover some of the other ones. Your next question was referring to the application for increased production on Brage. When you exceed 10%, you have to reapply for the production permit. Obviously, that has no impact for production in 2025 on Brage. It's just an annual thing that if you are exceeding your numbers that you have announced previously, then you have to inform the authorities. That is what we are doing there. That is something we have done in the past as well. The next question is if we are expecting a high decline rate on Draugen in 2025. No, we don't. Draugen actually has quite a stable decline rate, but it's also very low, which is also one of the reasons we are able to extend the lifetime of Draugen to 2040 and beyond. The reservoir there continues to give. We do not expect any high decline rates on Draugen. On the Statfjord guiding on 10 wells-12 wells at the Statfjord field, we have actually drilled 10 this year. Two of them will now be drilled in Q4. We have executed on the drilling program as we have previously announced on Statfjord. And on the production on Statfjord in 2025, increase or decrease in production, what we have done now is we expect to see an increase. Obviously, that's what we are working with every day on Draugen. That's also why we are sanctioning these new drilling, the new wells that will be drilled in the Statfjord area. So we do expect higher production, but we are not guiding asset by asset when it comes to production. And in the interview that we gave to Finansavisen, that was to reiterate, well, I guess there are two key messages in that interview. One of them is that we are focused on growth as a company. We have chosen a strategy of being the leading mid and late-life operator in Norway, which is a segment which is growing, which also is a good indication that we also want to be a significant player in Norway in 2030 and beyond. So we are still looking for opportunities inorganically. I think we can say that we have demonstrated success when it comes to inorganic growth, which is important for us to get good cash flows and good production. And also now also focusing on the organic growth, which is also important for an E&P company because we believe the NCS and the oil and gas market will stay strong for longer. So short-term decrease in production or the guiding that you have seen here is no indication of something contrary. We are focusing further on growth in OKEA. I think that covered everything, didn't it? Thank you, Svein. The next question is from Niklas Johannesen. What will happen with dividends next year? I think we have already answered that with the board will revert when we consider to be in a dividend position again. Yeah. And the next one is from Daniel Stenslet from Arctic. Can you elaborate on the CapEx split for 2025 and 2026? How much is Bestla and how much is Draugen electrification? Well, we do not really guide on CapEx by project, but I can say that the sum of those two sanctioned projects is just below 50% of the total estimates for those two years. And Bestla is somewhat more than the power from shore project. Yeah. Two questions from Sander Nielsen from Fearnley. Can you shed some color on the Arkenstone, Mistral, and Prins prospects in terms of potential resources? And congrats on the strong results. Second question, how much of the 2025 and 2026 CapEx will be related to exploration and decommissioning? We generally don't guide on pre-drill estimates and refer to the operator for such estimates. What I can say, I guess, is that the Arkenstone well is a high-risk, high-reward well, whereas Mistral and Prins is a smaller prospect, closer to our existing infrastructure. Of the 2025 and 2026 CapEx, we do not include exploration in our CapEx guidance, only the infill and production drilling, which is about one-third of the estimates, and there are no major decommissioning expected in the guidance period. Yeah. Next one is from Truls Lundqvist. In your production estimate for 2025 and 2026, are you estimating continued drilling at Brage and Statfjord? And the second one, how does the company look at dividends versus repurchasing of shares? Yeah, maybe I can cover the drilling question there. The future success of both Brage and Statfjord sits within an effective drilling program. So the answer to that is yes. We will continue to do drilling both on Brage and also on Statfjord and in the surrounding areas. So that is very important for us. So that will continue. As for dividends and repurchase of shares, we have generally had the preference towards cash dividends. I think to keep also liquidity in our share at a reasonable level, that has been one reasoning for that preference. Thank you, Birte. Next, two questions from David Mirzai. Given your prior focus on lower-risk drilling and infrastructure-led exploration, does the participation in the high-risk Arkenstone well signal a change in strategy? Second question, does the fair value reversal in E&P suggest that you have been too conservative with your reserve write-downs in the recent past? Yeah, when it comes to the Arkenstone well, Arkenstone was a result of a farm-in something we did with Equinor. So Equinor entered into the Mistral well that we were operator for, which is a high-pressure, high-temperature well. And we, as a company, at least back then, did not have many experiences with drilling HPHT wells. So we farmed in Equinor to actually take the operator role there. And in return, we farmed into the Arkenstone with 20% because it's a very interesting area as well. So that's the result why we ended up in the Arkenstone well, which we think could be a very promising and exciting area to go into. So it's not a change in strategy as such. Whereas the fair value reversal, I think we try to be quite balanced with respect to conservatism when we are assessing, when we are doing our impairment assessment. But I think rather it represents that we have been able to enter into a sales contract on terms that have been beneficial to us. And as Svein mentioned, the agreed purchase price is above our holding value. So I think that is more the answer to why we are now reversing the previous impairment. Yeah, the last question on the line is from Marcus Jansen. Could you share OKEA's current estimate of the Brage field's expected lifetime considering the production contribution from Bestla? Yeah, just a few words on that. We are currently working on a lifetime extension application for Brage, which obviously will consist of more production from the existing Brage reservoir. That's also why we are exploring in the area with the Prins well, because we think there could be potential around there and also Bestla. But in the current calculations for Bestla and in the current production permit, that is expiring in 2030. So how much beyond 2030 we are able to actually generate is something we are working on now. But obviously, if we can extend the lifetime production not only from Bestla, but also from the existing reservoirs on Brage, we'll really contribute to that. So that is something we need to get back to. But it's in the core of our strategy that we want to extend the lifetime of these assets so the commercial last barrel can be produced much later than was originally planned, same as we have done on Draugen. So we need to get back on the exact lifetime extension when we have more firm resource details, which is the foundation for the extension. Thank you. Then we hand it back to the moderator to see if there are any more questions on the line. We have no questions in the queue on the phone line. Okay. Okay, thank you very much for your questions and that you attended the presentation. And look forward to see you again when we present the Q4 results in January. Bye for now.