Good morning and welcome to Aker BP's presentation of our third quarter 2025 results. Today's agenda reflects a strong quarter with clear momentum in both operations and strategy. We'll start with an update on the operational performance, which continues to deliver solid results. Next, we'll move to our field development portfolio, where we remain firmly on track. We're also very pleased with our exploration results. So far this year, we've made two significant discoveries: Omega Alfa and Kjøttkake. With several additional wells currently being drilled, we see the potential to reach 100 million bbls discovered in 2025, net to Aker BP. As always, CFO David Tønne will take us through the financials later in the presentation. In the third quarter, production averaged 414,000 bbls per day, in line with previous quarters. This time, we had a planned maintenance shutdown at Gryggåsen, similar in impact to the maintenance shutdown at Valhall and Ula in Q2. Despite the shutdown, portfolio-wide production efficiency stayed high at 96%. Other assets, including Johan Sverdrup, continued to perform very well, with efficiencies ranging from 92% to a nearly perfect 100%. Looking ahead, we expect our assets to maintain strong performance, even as natural decline offsets some of that strength. Based on the strong year-to-date production and updated forecasts for the remainder of 2025, we are raising our full-year production guidance to 410,000 bbls- 425,000 bbls per day. Now, let's have a quick look at our cost performance. Reported unit costs edged up to roughly $7.60 per barrel this quarter, but as David will come back to, the underlying unit cost was essentially unchanged from the previous quarter. We remain firmly on track to deliver on our full-year guidance of $7.00 per barrel, a level that is highly competitive in the industry and underscores the strength of our assets and operations. On CO2 e missions, the picture remained consistent. Our emission intensity held steady at 2.9 kg per barrel, as it's been throughout the year. This is an industry-leading level that continues to set the benchmark. Simply put, we are the global leader in low-emissions oil and gas production. Earlier this year, we outlined our ambition to sustain production above 500,000 bbls per day beyond 2030 and to pursue further growth. I can assure you, we work every day to make this a reality. On this illustration, the dark blue area shows the current business plan, that is, production from existing fields, ongoing field developments, and regular IOR activities. Key growth drivers include the large-scale Yggdrasil development, which contains now the Istavik discovery, the Valhall PWP-Fenris project, and a series of tiebacks to Alfheim, Skarv, Gryggåsen, in addition to Johan Sverdrup phase three. This outlook supports our target to produce around 525,000 bbls per day by 2028. Beyond 2028, the light blue wedges illustrate our potential to sustain production over 500,000 bbls per day for infill drilling and tieback from known discoveries across the portfolio. Progress this year, especially our exploration success, strengthened my confidence in this trajectory. Now, looking further ahead, we see significant growth potential beyond our current outlook. Continued exploration success and targeted M&A provide a clear path to expand our production base well into the next decade. A recent example is our increased ownership in the Kjøttkake discovery, where the partnership is already actively evaluating possible development scenarios. In total, this is our ambition, and we are well equipped to deliver it. We have the people, the assets, the supplier, the digital ecosystem, the capital, the track record, and the project to make it happen. Bundled systems consist of a lot of pipelines bundled together in one pipe, which makes it possible to install everything in one go. The unique feature with this is that we actually commission all this work before we start towing it out. When it arrives in the field, it's ready to go. We just connect it up with the spools into the templates, and it's the fastest way of developing a field. Impressive work by the Subsea Alliance, indeed. The launch of the Yggdrasil bundle is spectacular, and it's now been safely installed at the field. As we heard in the video, because we all do all commissioning work before sail away, it is truly the fastest way of developing a field. Our project continued to advance steadily, with several key milestones achieved in the recent months. These include the successful offshore installation of four of the five jackets at Yggdrasil and Valhall PWP-Fenris, installation of subsea templates, and the completion of the Fenris drilling campaign. These achievements reflect the scale, pace, and precision of our execution. They are the results of close collaboration across teams and partners, and they mark critical steps towards delivering on our long-term value creation. We are now at the midway point of our execution phase, with engineering and procurement nearly complete. We're also at the peak construction, and we have reached the point where modules are being assembled into complete platform units. This gives us clear operational visibility into the remaining work and resource needs. For the projects, they remain on schedule for planned startups in 2026 and 2027. Let me now turn to exploration. When we last met in July, we had drilled the first sections of the Omega Alfa well, which confirmed commercial oil volumes in the range of 20 million bbls- 40 million bbls at that point in time. Now, over the summer, we completed this exploration campaign. The result was a significant oil discovery that adds substantial new resources to the Yggdrasil area. The recoverable volume is estimated at 96 million bbls- 134 million bbls of oil equivalent. It is among the largest commercial discoveries in Norway in a decade. Building on the momentum from the oil discovery at Istavik in 2023, this marks a major step towards our ambition of producing more than a billion bbls from the Yggdrasil area. The success is also a result of strong collaboration between our own teams and our Alliance partners, and a testament to how new exploration methods push the boundaries. Luckily for us, we equipped the team behind the discovery with a camera during the operation. Here is their report. What's really making this well remarkable isn't just the fact that we're finding a lot of oil. It's how we are finding it. We are drilling ultra-long reservoir sections using advanced geosteering to map the subsurface as we go along with unprecedented accuracy to pinpoint the oil accumulation with high confidence. This isn't just a regular well. This is a huge leap forward in how we explore. We're currently drilling the fourth lateral on the Omega Alfa well in the Yggdrasil area, where we're targeting several structures: the Omega, the Alfa, Alfa South, Sigma Northeast, and P. Right now, we're steering the wells towards the Sigma Northeast and the P structures. Things are looking really good. We are drilling in about 10 m oil, a good indication that we are exactly where we should be. We are currently geosteering the well, which means that we are placing the well optimally in the reservoir. Normally, we are doing that to optimize the production well, but in this case, we are drilling an exploration well, and we are optimizing the well to optimize the data acquisition. We're collecting a massive amount of data with this well, probably more than has ever been collected before in an exploration well. This data will significantly reduce the subsurface uncertainty. The Omega and Alfa well are a continuation of the work we started two years ago with Istavik. There, we went from exploration drilling to development in just two years. Geologically, this is very similar to Istavik. We are seeing a thin oil column trapped beneath an infrared reservoir shale. In this setting, an efficient seal for hydrocarbons. Two years ago, with the Istavik well, we set a new benchmark in exploration, achieving more than 30 km of reservoir exposure. A year later, on Free Gamma Geopilot, we further pushed the limits and drilled length and ROP versus hole cleaning. Since then, we've gotten the best-performing rig in the market back on contract. We have done several performance-improving upgrades and equipped the rig with wired pipe. This puts us in a position to not only push the limits but make a step change in performance. We started off drilling the longest well ever drilled in Norway with the standard exploration well design, and we did it following the low flow and high ROP strategy. We have debunked several old drilling practices and proved the technical limit is still to be reached. This is only the beginning, and I look forward to continuing pushing the limits for what's technically feasible while drilling a well. Thank you, Osmund, Torstein, Hannah, and the rest of the team for the great work. Yes, Hannah, I agree, this is only the beginning. Omega Alfa is not just a big discovery. It represents a step change in how we explore. The methods proven here will shape the next chapter of exploration in the Frigg area and beyond. Why does that matter? It gives us speed, precision, and confidence. It means, in reality, that we can shorten the time from discovery to development and thereby unlock value faster. Frigg was once a giant gas field, decommissioned after producing 700 million bbls of oil equivalent of gas. Today, with new insight and new technology, we see significant oil potential in the same area. This is a major upside for Yggdrasil and for Aker BP's long-term growth. Our exploration team has also delivered other strong results this year. In the first quarter, we made a promising oil and gas discovery in the Kjøttkake in the Northern North Sea. The reservoir shows good quality, and estimated gross recoverable volumes stand at around 50 million bbls. Located near existing infrastructure in the Troll Juhla area, this is clearly a commercial discovery. We have, after the discovery, increased our ownership in the license to 45% from 30%. The partnership is already evaluating development solutions. Together with Omega Alfa and the smaller e-prospect at Skarv, we have added approximately 75 million bbls net to our resource base from exploration in 2025. The year is not over. We are currently drilling several exploration wells, including Natruisdelen in the Yggdrasil area and the Equinor-operated Lufven and Langemann west of Utsirahøy. With the risk potential in the remaining wells, total net discoveries could reach 100 million bbls before year end. In that case, making 2025 our most prolific exploration year since the Johan Sverdrup discovery in 2010. Good morning. As Karl highlighted, we delivered another solid quarter with strong operating cash flow driven by stable production, high efficiency, and good cost control. We also maintained good progress and remain on track with our development projects. In addition, we significantly strengthened our resource base through the Omega Alfa discovery and by increasing our interest in Kjøttkake. At quarter end, our financial position remains strong, with ample liquidity and low leverage. This allows us to navigate market volatility while executing our investment program and maintaining a resilient dividend to shareholders. Altogether, this quarter marks another step forward on our value creation plan. Let's now take a closer look at the main drivers behind the results. Net production was on par with the previous quarter, impacted by a planned shutdown at Gryggåsen for maintenance. Production in Q3 was 414,000 bbls of oil equivalent per day, and underlift brought sold volumes down to 396,000 bbls. Operating costs increased to $7.6 per barrel, slightly up from the last quarter due to the production mix and some one-off infrastructure costs. Year to date, the unit cost is $7.1, and we are on track to deliver on our full-year guidance of around $7. Cash flow from operations reached $2 billion in the quarter. The main drivers were good operational performance, low tax payments, and stable working capital. Investments were in line with the second quarter at $1.9 billion, reflecting high activity across our project portfolio and a slight weakening of the U.S. dollar since the first quarter. Within financing cash flow, the main item was the dividend payment of $0.63 per share in the quarter. Zooming in on a few items in the income statement. With slightly lower sales volumes but marginally higher realized prices, revenues were stable compared to the second quarter at around $2.6 billion. As mentioned, the cost per barrel produced increased a bit, but total production costs in the P&L were actually down due to the underlift. Net financial items were impacted by currency losses from a weaker U.S. dollar, but on the positive side, our NOC hedging program, which covers current tax liabilities and investment plans, generated $11 million this quarter. Impairments totaled $173 million related to technical goodwill on Johan Sverdrup and Valhall. The main driver is that we produce from assets where technical goodwill has been allocated in previous M&A transactions, and since technical goodwill is not depreciated under IFRS, we must impair goodwill as we produce from the assets all other things equal. Since goodwill impairment has no tax impact, this leads to a high reported tax rate of 80%. Adjusted for impairments, earnings per share were $0.73 in the quarter, and the effective tax rate was 71%. For more information on technical goodwill and impairments, I recommend, as usual, watching the explanatory video that we have published on our IR website. Now, let me also briefly comment on cash flows. The third quarter marked the start of the new tax payment process for E&P companies in Norway. Tax for the year is now paid in 10 monthly installments, with a final settlement in the fourth quarter of the following year. The first payment is in August, with no payments in January or July. With only two installments this quarter and investments at peak level, taxes paid were relatively low at around $300 million. As mentioned, cash flow from operations then ended at $2 billion in the quarter, and then free cash flow was around $0.24 per share. Turning to the balance sheet and liquidity. With strong operational performance flowing through to the financials, we exit the third quarter with a solid financial position. As shown in the chart to the left, net interest-bearing debt increased to $5 billion. At the same time, tax payables decreased from almost $1.8 billion- $1.6 billion. Our leverage ratio remains low, but as expected, ticked up slightly to 0.5x net debt to EBITDA. Total available liquidity stands at $5.6 billion, providing ample flexibility. The quarter-on-quarter decrease reflects $400 million lower cash and cash equivalents, of which almost $200 million was used to reduce tax payables, as mentioned. We have also progressed the refinancing of our existing $3 billion revolving credit facility, which was set to mature next year. Last week, we secured commitments from a bank syndicate to establish a new facility of a minimum of $3 billion. This is split into a liquidity facility of $2 billion with a five-year tenor, including extension options that could take maturity out to 2032, and a working capital facility of a minimum of $1 billion with a three-year tenor and an option to extend maturity to 2029. A strong balance sheet with financial flexibility remains important as we move into the final stretch of 2025, and we are now halfway into our 2023- 2028 value creation plan. Earlier this year, we completed a comprehensive project review where we also updated the investment estimates for 2025- 2028. This was reported at our second quarter presentation, and these estimates, as shown on this slide, remain firm. We continue to expect 2025 to be the peak investment year, with capital expenditures reaching around $6.5 billion before tapering off from 2026 and onwards. As more than half of our investments are denominated in Norwegian kroner, our estimates in U.S. dollars are sensitive to FX fluctuations. Over the last four years, we have benefited from a weakening of the Norwegian kroner versus the U.S. dollar. To lock in some of that benefit and to mitigate the financial exposure to a potential strengthening of the Norwegian kroner, we have hedged between 75% and 90% of our planned Norwegian kroner expenditures in 2025- 2027 at an average dollar NOK rate between NOK 10.5 and NOK 11. The financial effects of this FX hedging will not impact reported CapEx. They are recognized on another line in the financial accounts. As shown in the notes to the balance sheet, our FX derivatives positions are valued at approximately $150 million. 90% of this relates to hedging of our planned NOK expenditures, and the rest relates to tax payables. With a 22% tax rate on FX derivatives, the after-tax value of our spend-related hedges is $107 million. Just for comparison, this corresponds to over $800 million in pre-tax CapEx under the 2020 tax system, which applies to most of our investments. As mentioned, we are now halfway into our 2023- 2028 value creation plan. By the end of 2028, we estimate to have generated between $9 billion and $13.5 billion in cumulative free cash flow, depending, of course, on how oil and gas prices develop over the period. In turbulent and volatile times, resilience matters, and we have built the financial resilience to withstand oil price volatility. Consequently, our financial metrics remain robust across most plausible oil price scenarios. Assuming a continued 5% annual increase in dividends, our leverage ratio remains comfortably below the internal threshold of 1.5x and well within the bank covenant limit of 3.5x. Even in a prolonged $50 oil price environment, conservatively assumed from the beginning of 2025, our modeling indicates that leverage only temporarily exceeds 1.5x in 2026 before declining again in 2027. Given that our averaged realized oil price is around $70 per barrel for the first three quarters, and approximately 40% of our estimated oil exposure for the fourth quarter is hedged at $65 per barrel, this downside case is conservative. In summary, our value creation plan is on track, and we have the capacity and resilience to fund investments and deliver attractive shareholder distributions in the years to come. Turning quickly to shareholder distributions, our guiding principle is to maintain a resilient dividend that reflects our financial strength and outlook. Our ambition to grow the dividend by at least 5% annually through this investment cycle remains firm. For 2025, we are delivering on that commitment with a total dividend of $2.52 per share. We have already paid three of the four quarterly installments, and the Board of Directors has resolved to pay the fourth installment of $0.63 in early November. Let me round off with a review of our guidance for 2025. Production averaged 423,000 bbls per day in the first nine months, above the top end of our full-year range and slightly above our expectations. We still expect some natural decline and minor planned maintenance in the fourth quarter, but with three quarters behind us, we are raising the full-year estimate range to 410,000 bbls- 425,000 bbls per day. Production cost is $7.10 per barrel year to date. Although the recent strengthening of the Norwegian kroner adds some risk to the full-year estimate, we maintain strong cost control and still expect to end the year at approximately $7 per barrel. Investment activity remains at peak levels, with construction and drilling operations running at full speed. We've invested $4.9 billion year to date and maintain our full-year guidance at approximately $6.5 billion. The year-end outcome will depend on progress, phasing effects, and currency levels. Note that benefits of FX hedging do not reduce reported CapEx but are recognized elsewhere in the accounts. Exploration results have been strong in 2025. We now expect to drill 18 wells in total, and the full-year estimate has been raised to around $500 million pre-tax, driven by the high activity level and the extended scope of the discovery wells. Abandonment activity is also on track. We revised the estimate down in the second quarter to around $100 million, and we now expect to end slightly below that level. With that, I'll hand it back to Karl Johnny Hersvik for some concluding remarks. Thank you, David. While I do appreciate that David's presentation might be the highlight for some of you, let me wrap up with a few key messages before we move to Q&A. We have delivered a solid third quarter, operationally, strategically, and financially. Production was stable at 414,000 bbls per day, costs remained competitive, and our emissions intensity is at industry-leading levels of 2.9 kg per barrel. Based on our strong performance so far this year, we are raising our full-year production guidance to 410, 000 bbls- 425,000 bbls per day. We are executing on our strategy, and we continue to invest in safe and efficient operations, digital transformation, and low-emission solutions. Our major projects are on schedule, supporting our goal to reach production above 500,000 bbls per day in 2028 and to sustain that level well into the 2030s. Discoveries like Omega Alfa and Kjøttkake are clear examples of how we are building a resource base that underpins our long-term production profile. Our robust financial position and resilient cash flow enable us to deliver attractive, reliable dividends, even as we continue to invest in profitable growth. We will now take a short pause before opening the Q&A session. To participate, please use the Teams link on our webcast page, and if you prefer to listen only, please stay tuned, and we will resume in one minute. Welcome back. We will, as announced, now do the Q&A. As usual, Kjetil Bakken, our IR champion, I would say AI champion, actually, will serve as our quiz master also during this Q&A round. I'll hand over to you, Kjetil. Thank you, Karl. We will go straight to the first question, which comes from Tianhong Bi from Citi. Please go ahead. The line should be open. Hi, morning, guys. I've got two questions, please, if I may. The first one is on production cost guidance. Based on the midpoint of your new production guidance, volumes in the fourth quarter look to come in around 400,000 bbls per day, and that's 3% below this quarter. Linked to that, with the year-to-date average at $7.1 per barrel, I think you need roughly $6.6 per barrel in the fourth quarter to hit your $7 target for the full year. That's 13% down from this quarter. That feels quite tight and doesn't quite add up, given the lower production and you just talked about the Norwegian kroner strength adding some extra risk. I'm just wondering what's driving that step down and where you're seeing the main cost reduction coming from. The second question is on Omega Alfa and the broader exploration potential around Yggdrasil. Should we think about these discoveries being developed as a series of subsea tiebacks to Yggdrasil? Assuming those FIDs come after Yggdrasil is on stream, we're essentially talking about incremental volumes coming a bit later, say around 2030, rather than immediately extending the 2028 production peak. If you could just confirm that, please. Thank you. Okay, production cost, David. Do you want to talk about that? I can do that. The guidance for the full year is approximately $7 per barrel. As mentioned in my presentation, we had some one-off costs related to infrastructure in the third quarter. When we look at the best estimate that we have for the fourth quarter, we expect to end up roughly at $7 per barrel for the full year. There is no magic to it. It's just underlying costs are stable, and we have had maintenance on a few assets over the past two quarters, and now we're back to some more stable production in the fourth quarter. Thank you. Turning to Omega Alfa and development concepts, it's of course quite early. I would say there are two possibilities here, depending on what the final one or two exploration wells in the area will show. You can either have a series of subsea tiebacks, or you will have some sort of unmanned installation in the area trying to capture all of the volume to the west of the Yggdrasil area. Regardless of how these solutions will be developed, this will be a plateau extender on the current Yggdrasil plateau, simply because with the current volumes and the inclusion of East Frigg, we don't have processing capacity at Hugin A to take in more volumes. In that case, you can see this as a plateau extender on the Yggdrasil plateau, and of course then coming on the back of the curve that you saw on this strategy slide. It's adding volumes to the curve, and it's reinforcing the message of 500,000 bbls well into the 2030s. Good, thanks. Thanks very much. The next question comes from Anders Rosenlund from SEB. Go ahead, Anders. Thank you. Could you talk a bit about commodity hedging? You have a comment in the report indicating 40% oil price exposure covered for the fourth quarter, but how is your exposure for the first quarter and maybe for the first half of 2026? What's really the purpose of hedging at $65? Excellent, Anders. I think this is your domain again, David. I can do that. You're correct, Anders. We currently have 40% of our oil price exposure hedged at $65 using put option. When it comes to 2026, we don't have any commodity hedges in place. Our strategy is to be opportunistic, and when we see that the cost-benefit of putting in place hedges to both protect downside risk but also lock in value, we do that. That's the current positions and how we think about it also going forward into 2026. Okay, thank you. All right. Next question is from Theodor Sven Nielsen from SpareBank 1 Markets. Good morning, and congrats on our strong quarter. A couple of questions from me. First of all, on the exploration, you talked a lot about the strong exploration results this far in the year, which obviously is impressive. I was just wondering, looking into next year, is it tempting to increase the exploration activities and also increase the exploration spending? The second question that is on Yggdrasil, and last quarter we talked a lot about the increased cost on the Yggdrasil, and you say that the project remains on schedule, but often we see that the increased cost also impacts schedule. I just want to know, have you seen any changes to schedule in some parts of the Yggdrasil project at all, or is it only cost that you have seen increasing or changing compared to the PDO? Excellent. Thank you, Theodor. When we talk about the exploration, we've been rather active on the APA rounds or the annual acquisition rounds of licenses on the Norwegian Continental Shelf in the last four years, where the overarching objective has been to build a portfolio of interesting exploration possibilities, prospects, and targets in areas where we feel that we could actually aggregate volumes sufficient to make interesting field developments. I think this is now starting to play out. The Omega Alfa story is certainly a part of it, with Istavik and now Omega Alfa and then follow-up wells coming in 2026 and 2027. There will also be other prospects. For us, it's a long-term strategy. The other part of the same strategy is to maximize the volumes that we can create based on the number of dollars we spend on exploration. At this point in time, we don't intend to increase the exploration spend, but we intend to prioritize harder on the targets that we do drill in order to increase the yield of those exploration spends. We don't really see the exploration spend as a limiting factor at this point in time, to be quite frank. On Yggdrasil cost, the cost increase that we talked about in Q2, and I don't think we talked about it a lot, but the cost we discussed in Q2 was mainly related to changes in FX, additions of the Istavik into Yggdrasil, and then some added resources that were necessary to drive the different acquisitions of parts and, yeah, procurement elements in essence. Of course, some additional transportation costs, etc., etc. The answer is very simple. We are on schedule when it comes to the Yggdrasil development. We have met all the milestones necessary in the quarter, and there is no slippage on schedule. This is not your classical time-related cost. This is about us deploying capital to minimize risk. Okay, thank you. All right. The next question is from John Olaisen from ABG. Yeah, good morning, everybody. I love the videos of the Yggdrasil-related work and also the detailed comments on the progress. However, from the outside, it's difficult to assess the progress when we do not know the milestones that we should expect. I wonder if it's possible to give us some milestones, so what we should look out for going forward. For instance, like key sailaway dates for the last jacket and the topsides. What kind of subsea work should we be looking for you to report that this is installed? The drilling progress, for instance. Some milestones to what to look out for for the Yggdrasil development would be fantastic. Yeah, thank you, John. Quite a few of those milestones that you actually report have actually been achieved. We have installed all the subsea templates that are necessary. We are actually in the progress of drilling first the top holes and then the transport sections down to the reservoir as we speak. As you point out, we have installed the Munin jacket and the Hugin A jacket. The Hugin B jacket will be installed next summer. The key sailaway dates will also be next summer, where both Munin, Hugin A, and Hugin B will be transported from shore and installed on the field. Of course, the last milestone and the most important milestone of all will be the startup of Hugin in the first half of 2027. This is why I'm saying that we're really into the execution program. Is it possible to give some more dates on what kind of the key sailaway dates? I presume the jacket is going to be earlier than the topsides. Makes sense. The jacket first, I guess. This comes from an economist. If we install the Hugin B topside before the jacket, somebody's made an error. That's correct. I don't want to give dates at this point in time because we are in the process of finalizing the installing program. This is always a discussion between us and the TNI contractor. In this case, it's both Allseas with the Pioneering Spirit and Heerema. We are in the process of closing those windows. The normal way of doing this is you enter into a discussion, you reserve slots on a schedule, and then in January, possibly February, we will try to lock down those slots to make sure that we have a very firm date. Okay, fair enough. Thank you. Good luck with the progress. Thank you. Thank you so much, John. Thank you. The next question comes from Nash Pui from Barclays. Please go ahead, Nash. Hey, good morning, everyone. Thanks for all the questions. I've got two questions. He's got two questions. Are you ready? Absolutely, we can hear you well. I'm ready. I have two questions. Good morning, everyone. He's got two questions. Always has two questions. The next guy, you're still. Sorry, can you guys hear me? Yeah, there was some noise on the lines. I think we're clear. Go ahead, Nash. Go ahead. I think someone else opened his line. I also have two questions, if that's okay. The first one is on your production guidance. You had a very strong operational quarter. In Q3, you increased your production guidance twice in the year. Shall we think your new guidance is quite conservative as well? Will we be able to see any upside potential over there? My second question, probably for modeling purpose, how should we think about impairment into Q4? I noticed we had quite a bit of impairment in the last two quarters. Do you expect more over there for the next quarter? Can you provide a bit of color there? Thank you. Excellent. You're absolutely right. We have now increased the production guidance slightly over two quarters. We previously discussed this in one of these quarterly earnings calls, where I've been very frank saying that what we put in our production guidance is what we expect as a P50 number. The fact that we have slightly increased our guidance now, first in the second half and now in the third quarter, means that we are performing slightly better than our own P50 guidance. What you should expect is that we also follow this P50 rule when we now update the guidance. We are trying to be as transparent as we possibly can in the market and it wouldn't be a bad assumption to assume that the midpoint is quite close to our existing P50. From that, you can easily deduct the expected production in Q4. On impairment, David, this is your favorite topic in addition to tax, isn't it? Yeah, indeed, indeed. Quick on impairments, right? I'm sure everybody is aware now that we do have quite a lot of information on our investor web pages with regards to what technical goodwill is and how you should think about impairment related to technical goodwill. In this quarter, we also had impairments of technical goodwill. Technical goodwill has risen on the balance sheet through the acquisitions that we have done previously, and it's allocated to the various assets that we have acquired. What you should expect is that we will have impairments of technical goodwill, all things equal, as we produce volumes out of the assets that have technical goodwill allocated. The reason for this is that we are not able to depreciate technical goodwill. We test every quarter to see if there is a need to impair it. The variables, of course, are the underlying business. It's the, call it, assumptions related to commodity prices and FX, and actually also the forward curves, and then, of course, the production from the fields. All things equal, you should expect impairments, and if there are significant changes in the forward curves of commodity prices, that, of course, has an additional impact. Excellent, very clear. Thank you so much. Thank you. Next one. Next one is Victoria McCulloch from RBC. Thanks very much. Morning all. Firstly, on Omega Alfa, you highlight again the use of high-speed horizontal drilling in the current, I guess, the list of wells you gave for the remainder of this year and into 2026. Are any other wells using this method? Looking at Greg Olson area, you had IOR drilling at Edvard Grieg this quarter, I think. Have you seen any results from that yet? What are your expectations? In turn, what do you expect from Ivar Aasen, where production has been a bit weaker this year versus last year? Is there any guidance you can give us on when Symra and Solveig will be coming on stream next year? That'd be helpful. Thank you very much. Symra or Solveig. Okay, let's first talk about Omega Alfa. Omega Alfa for us is a test bed for basically two technologies, or three technologies really. It's, of course, wired pipe, which we really try to see what the operational envelope of that technology is. I think during Omega Alfa and these extremely long horizontals, we've discovered that wired pipe will now be used on all Aker BP rigs, both in exploration drilling and in production drilling, as we made a strategic decision to move as fast as we possibly can into wired pipe technology. I think that will be basically the standard now across all our drilling operations. The other test case was basically to see how downhole drilling tools and logging while drilling tools were interacting with these technologies and trying to optimize the drilling sequence, as Hannah talked about in her video. I think there is more de-bottlenecking to be done before we attempt that again. There is quite a strong force, or task force, working these topics both from the supplier side and from us as an oil company side. I'm expecting that in a few months, we'll have de-bottlenecked also that process. The last one is the whole kind of the data ecosystem, right? This is basically about understanding the drilling processes and being able to model and use machine learning to optimize the process. Also, here we have discovered some bottlenecks and are in the process of modifying those. As I said, you should expect that these technologies and these ways of drilling these wells are not only going to be a part of our exploration program going forward, they are going to be a part of our production drilling program going forward. This is one of the reasons why we test the barriers that Hannah talked about in the video. On the specific question on this, I don't think a lot of these wells that are currently on the program, with the exception of inclusion of wired pipe, will basically lend itself to this kind of exploration method. What you could say is that it gives us an optionality if we make a discovery to very, very rapidly do appraisal drilling and acquire a sufficient amount of data to rapidly move from exploration and into a feasibility phase and from there to a development phase. It basically opens up the toolkit. Omega Alfa in itself was, in my way, a way of basically testing where the current technological barrier was. I can assure you that we found it on many levels. Greg Olson, yes, we have drilled a few infill wells, two if memory serves me right. They are either just set on stream or about to come on stream. I think the results are pretty much as expected, and the net results will, of course, be a part or are a part of our production guidance going forward. Your discussions around Olson, I agree that this has been a bit weaker this year. This is partly because of lesser performance than we expected from Hans, but also because we have higher performance from Greg. As we're now optimizing the area, that means that we have a bit lower production from the Olson area into that totality. Your last question was. I think it was Evert Olsen IOR campaign next year. Was that right, Victoria? Was that the last question? It was just on the tieback timings for the adding into Skarv's oil. Yeah, we haven't been very specific, but you're absolutely right. They will come on stream in 2026. Appreciate that. Thanks very much. Thank you. Thank you. Next question is from Irene Himona from Bernstein. Thank you. Good morning and congratulations on the numbers and the exploration success. I have only one question on distributions. For 2026, your guidance is for production to dip and for leverage to move up. In your stress scenario, $50, leverage would move above your 1.5x ceiling. Currently, of course, commodity prices are weakening. You told us you're not hedged into 2026. I just wanted to understand whether you would consider a, let's say, one-year holiday to the aspiration to grow the dividend at 5% in the event that we approach your stress case in order to protect the balance sheet. Thank you. Yeah, I want to talk about distribution, David, and holidays. I can do that. I can definitely do that. The current value creation plan that we are in the middle of, that's something that we have planned for since the end of 2022. We came into this period with a lot of financial flexibility and low leverage. Through the investment cycle, we have been increasing leverage to invest in growth. When you look at the, call it, stress test scenario or the $50 scenario that I presented today, which is similar to what we also showed in the last quarterly presentation, that's assuming a $50 oil price from the start of 2025. I mentioned that that is probably too conservative of a case when you think about 2025 in isolation at least. Who knows what oil price will be in 2026? We're currently trading at around $62. We have the financial flexibility to withstand volatility, and we've been very clear on the ambition of the company to grow the dividend by a minimum of 5% if oil price is above $40. When it comes to leverage ratio targets, what we have said is that we don't want the leverage ratio to exceed 1.5x for extended periods of time. We are comfortable to exceed that for a shorter period of time when we know that when production of the new assets comes on stream, we will be deleveraging back down again. That's how we think about it holistically. If I may, David, I think when thinking about low oil price scenarios in Aker BP, it's worthwhile looking at the history where we've been quite good in utilizing these periods of low oil price and being countercyclical. That will also be the case if we end up in a situation where the oil price dips down to $50 a barrel. I think there are many companies who will struggle significantly more financially than Aker BP will in that scenario simply because of the strength of our balance sheet, the low cost, and therefore the high cash flow that we have in that period. While all things equal, we, of course, like high oil price scenarios better than low oil price scenarios. I think it's fair to say that I'm also a bit ambivalent on these low oil price scenarios because they do create a lot of opportunity for companies like Aker BP. Thank you. Next question is from Chris Wheaton from Stifel. Chris is for once silent. We can't hear you, Chris. I think we'll move to the next caller. Let's move to the next one and come back to Chris once he fixes his audio. Next question will be from Matt Smith from Bank of America. Hi there, good morning guys. Hope you can hear me well. Good morning. Absolutely. A couple of questions from me. The first was on Johan Sverdrup. I mean, given the strong performance year to date and now what you're seeing from the multilateral performance, I just wondered if that's changed your expectations at all around how and when the project will come off plateau. That would be the first one. The second one, back onto the dividend. Rather than ask you about dividend holidays, I really wanted to ask, what would give you the confidence to raise the dividend beyond the 5% per annum? It seems like you're very happy to do that in a $60 oil price environment, although correct me if I'm wrong. It seems to me that this relates a lot to de-risking your growth project. Are we there yet or do we need to get much closer to first oil to unlock upside to that 5%, please? Yeah, so first on Johan Sverdrup, and I can do that because it's relatively easy. David, you can answer the hard questions around dividend. When it comes to Johan Sverdrup, we are pretty much spot on our internal expectations on the Johan Sverdrup performance. In short, that makes the answer to the second part of your question quite simple. There are no reasons to make any changes to our expectations to Johan Sverdrup that have been previously communicated to the market. We're pretty much spot on d ividends, and this time increase of dividends. Exactly. I think when you look at Aker BP, the dividend capacity that we have is large, and we have, call it, a fundamental philosophy that all the value that we create in Aker BP will be distributed back to shareholders. The policy is a minimum of 5% per year increase through this investment cycle. If you look at the history, we have exceeded that, call it, minimum threshold on a multiple of occasions. With regards to giving you sort of yardsticks with regards to what would we need to see in order for that to be more than, call it, 5%, I don't think I will go into that discussion. That's obviously a board discussion falling also for guidance for next year. What I'll say here is that the base case for Aker BP is a minimum of 5%, and then I'll stop there. Okay, thank you very much, guys. Okay, all right. Now let's make another attempt with Chris Wheaton from Stifel. We are still not hearing you, Chris. We'll circle back to you later, but we'll take Mark Wilson in the meantime from Jefferies. Please go ahead, Mark. Okay, thanks, gentlemen. Matt beat me to the question on Johan Sverdrup. You say it's pretty much spot on internal expectations. That was, I believe, for the plateau to last well into 2025, and that's where we are. I guess the assumption is then that this starts to come off plateau into 2026. Added to that, I think the most important thing you've said to me in this results is this making wired pipe a standard on both development and exploration. You're seeing the advantages and the benefits coming through. My question therefore, is that a standard that Equinor would be using on Johan Sverdrup? More to the point, even if it isn't, could you explain how that would benefit, let's say, any forward production expectations for, for instance, major developments like Johan Sverdrup and indeed the whole Edvard Grieg area? Thanks, guys. Okay, so the three key benefits of wired pipe are basically a lot better. The basic underlying principle is that you now have an ability to communicate with the downhole tools on a megabit bandwidth and not on a single-digit bit bandwidth. It's a fundamental step in your ability to transport information in the well. It also gives you information on the pressure and temperature and the, call it, fluid movements throughout the well from the very end of the drilling bit all the way up to the rotary, right? That's the basic technology. That gives you three advantages. One, total control of the well at all stages, so you're much better at anticipating what's happening. Two, you can actually drill significantly faster because you're not limited by empirically modeled but by actual restrictions as measured in the well. Three, it gives you an ability to move from manual control to autonomous control because you now have a data stream that goes all the way from the bit all the way to the rig equipment. Those two are basically transforming the way we drill and basically means that we can increase ROP in almost all sections. The upper sections will, of course, be limited by the total volume of rock removed from the ground and therefore the kind of solids handling on the rig, whereas the lower sections, and particularly the reservoir sections, they are basically limited by our ability to steer. This is one of the reasons we're interested in this. Think of this as a fundamental step up in performance but also a fundamental step up in our ability to place the well inside the reservoir and therefore increase ultimate recovery. I think those two are basically universal truths for pretty much all production drilling, while they might be more valuable for highly complicated reservoirs than for reservoirs like Johan Sverdrup where the drilling is actually quite simple. Okay, therefore, the reservoir model for larger reservoirs like Johan Sverdrup is not necessarily going to be affected by this, to your point, outside of Gryggåsen or the Alfheim. Which other producing fields that you use do you think would be benefited therefore? With the exception of Valhall, pretty much all of them, simply because you are increasing your drilling speed and you have better control over the reservoir. Frigg Gamma Delta, which is a prior and dominant case in the Yggdrasil development, is obviously an interesting one. Also, drilling in Alfheim, where we're following thin oil layers and the frost in the Frost Gaddic, is things that are ahead of us at the moment. We just entered into the license in Kjøttkake after the discovery. That's also an injectite where you could see the same benefits as in Alfheim. Quite a few of these, call it, more challenging reservoirs will be, it will be highly beneficial to utilize this technology. That goes for also all infill drilling and IOR drilling. Okay, thank you very much. I'll hand it over. Thank you, Mark. Let's make one last attempt to bring in Chris Wheaton, who had a question and obviously had some trouble with the audio. I hope you can hear me now. Absolutely, Chris. Good to hear you. I'm sorry to be the last question and keeping you from your day jobs. Two, if I may. Firstly, could you talk about the risk mitigation you're looking at about the offshore construction phase of the major project? This is the point at which your construction process starts to interact with everyone else that's also going offshore in the next two years because of the Norwegian tax changes of 2022, which means that it feels like a lot less of the construction process from here is in your control and a lot more is down to other factors like weather and what other people are doing. I'm assuming other people aren't going to be as good as you. Could you talk about those mitigation factors? I had a follow-up on another question about the exploration. Yeah, sure. First of all, in terms of conventional field development, you usually have quite a bit of hookup and that kind of construction work offshore. That is not going to be the case for these fields. These are going to be installed pretty much complete, and the only remaining work of volume will be commissioning work. When it comes to risk mitigation, we now had behind us two very, very active offshore seasons where we have produced in excess of 1,400 offshore days of installation of pipe, templates, jackets, etc., etc. In many ways, the majority of the offshore construction in terms of complexity is actually behind us. What is ahead of us is the topside installation, which will rely on weather, essentially, but where the capacity is actually quite good in the 2026 season. We have two remaining pipe lays in the next season, and then it's basically standard, I would call, surf work where we hook up subsea templates and pipelines and that kind of thing. The risk in the offshore construction, if there was a big risk in offshore construction, is probably more in the 2025 season than in the 2026 season, even though the volumes installed in terms of tonnage will obviously be higher in 2026 than in 2025. The complexity is actually lower. Okay, that's very clear. Thank you. The second question I have is on exploration. If you include your success at Omega Alfa this year, total discovered volumes on the NCS since 2011, so the year after Johan Sverdrup was discovered, adds up to just a bit less than a billion BOE. Norway is producing 1.4 billion BOE a year. What does that exploration or that lack of exploration success mean for the way Norway has to do exploration in the future? Is there a strategic reason here that actually you need more consolidation of exploration processes to get better resource recovery, which is ultimately what the government is going to want out of this whole, want the industry to deliver out of the whole exploration process? That's a good catch, Chris. The simple answer is that we need to get a lot better. Even though we end up with, let's call it 100 million bbls in 2025, production is probably ending up more like the 180 million bbls or slightly lower than 180 million bbls. Even with that kind of successful program, you want to reach a reserve replacement rate of one. That means there needs to be some sort of either step change in exploration success and/or some sort of consolidation in order to reach those targets. When it comes to exploration success, this is one of the reasons we're so focused on the use of artificial intelligence, digital tools, and matching that to our rather active program into the upper rounds the last four years. It will be a balance between our ability technically to prioritize the right targets and then drill them out with speed and efficiency, and then go very quickly from exploration success to field development and initial production. We're trying to compress that whole time schedule. The second one is, of course, understanding the reservoirs and understanding the Norwegian Continental Shelf. We are deploying significant amounts of capital and resources to develop agents and technologies that allow us to access every data point that's ever been amassed on the Norwegian Continental Shelf. Currently, we're in a situation where we can investigate everything that's been publicly publicized and also that we've gotten through different processes inside Aker BP, whether that is structured information or unstructured information, using artificial intelligence and agents. That's basically allowing us a much better view on where we believe the secondary migration routes and the remaining potential is on the Norwegian Continental Shelf. You're absolutely right. There needs to be a step change in order to deliver this. Going back to what I think we discussed in the second quarter, I don't think it was you who asked the question, but I basically boxed these remaining resources on the Norwegian Continental Shelf down to three boxes. It's what I will call subsidy backs, IORs, so smaller volumes. Then you have tight reservoirs, where we have large volumes of discovered oil in place, but currently very few developments. Second, there are HBHT, which haven't really been developed to the extent that has been on the U.K. Continental Shelf, for example. If you look at, take that checklist and you look at our current and past project execution, you will see that we have, for a long time, tried to become the master of IOR targets and field developments and subsea tiebacks. I think we're pretty good, trying to get better. Fenris was our test case, our exam, so to speak, on HPHT, and we're now past the drilling campaign on Fenris, discovered more volumes than we assumed, so there might be one additional well in 2027 on Fenris. We are in the process of dipping our toes into tight reservoirs, both becoming significantly more productive in exploration, but also amassing and assessing and ultimately producing the resources that exist in those categories. Those are our two basic lines of thought when it comes to the organic side. As you know, we are always up for a good deal if that happens. Always up for a good deal. No, that's great. That's a great answer. Thanks very much indeed, and apologies for delaying the Q&A with my tech this morning. No worries, Chris. Back to the questions. Yes, there seems to be no further questions, so I'll leave it back to you. Thank you for following us this morning. We will continue to do what we do best here in Aker BP, and that is to produce, develop, and discover oil and gas also in the next quarter. I'll see you in about three months.