Good morning, and welcome to this presentation of Aker BP's third quarter 2023, which will, as usual, be presented by our CFO, David Tønne, and myself. As usual, too, after the presentation, there will be a Q&A session. Now, let me briefly start by touching on some of the highlights. Production was 450,000 barrels of oil equivalents per day, a decrease from the second quarter due to a mix of planned and unplanned maintenance activities. Even so, the revenues increased due to higher oil prices. Furthermore, we continued to demonstrate cost discipline, and we maintain our position as global industry leaders on low emissions. We're also really happy to report that our projects are on track. All major contracts have been placed, and we have now started fabrication activities on multiple sites, while the CapEx estimates remain stable. We are, of course, very happy to see that production started from Kobra East & Gekko about 5 months ahead of plan. This strong performance is also visible in the free cash flow, which covered our dividend more than 3 times. As we have now put 9 months behind us for 2023, we are also today fine-tuning our full year guidance on production and OpEx. Aker BP delivered a good production performance this quarter with 450,000 barrels of oil equivalents per day. This is approximately 6% lower than the previous quarter, and the main reasons for the drop were planned maintenance on Alvheim and unplanned shutdown at Valhall, and natural decline on Edvard Grieg. As a result, the production efficiency on our operated fields decreased to 89%, compared to 96% in the second quarter. Production at Johan Sverdrup was marginally higher in the second quarter, and our total company production in the third quarter was in line with our communicated expectation. This performance has allowed us to narrow our production guidance for the full year, which David will discuss later. In the third quarter, we reported a low cost per barrel produced of $6, marginally up from the record low level in Q2, but considerably below the $7.2-$7.3 we saw in previous quarters. I am very pleased with this strong performance, which to me demonstrates that our operational improvements over the past few years have had significant cost effects. The reduction is caused by a combination of factors, including high efficiency over time, lower well intervention activity, lower power cost, and a weakening of the Norwegian kroner, which is the base currency for the most of our operation expenses. With such a robust performance in the first nine months of the year, we are announcing a further lowering of our full year estimates to a range of $6.0-$6.5 per barrel today. Of course, our fundamental goal and top priority is to ensure the safety of our people, and as I've stated multiple times before, we firmly believe that safe operations go hand in hand with overall operational performance. However, despite our strong safety performance within the industry context, it would be today incorrect for me to say that I'm satisfied with our safety performance over the last couple of quarters. During this period, the number of personal injuries has been at an unsatisfactory level, causing the TRIF level to increase to about 1.6. Although we observed fewer injuries in the third quarter than the previous one, it's important to note that none of these injuries were severe. However, the bottom line is that they should have not occurred. We are investigating each incident to learn from them and to improve. In the third quarter, we continued to deliver top-tier performance in CO2 emissions, keeping our emissions below three kilograms per barrel produced, and we are consistently working towards reducing our emissions from our operations. For 2023, we have set a target to reduce our climate footprint by at least 4% through improved energy efficiency. Judging by our progress to date, I am confident that we will surpass this target. Such continuous improvements are a crucial component of our strategy to achieve net zero emissions across our operations by 2030. Beyond that point, we will balance out our remaining emissions through carbon capture. With the acquisition of Lundin, we have already secured a portfolio of nature-based carbon capture project that cover about half of our estimated requirements for the 2030s, and we plan to go further and expand this portfolio going forward. It's probably also worth mentioning that we are exploring the possibility for underground carbon storage on the Norwegian Continental Shelf. To date, we have been granted one license, and we have recently completed a seismic survey on this license. At the present, we see this as an option that could potentially be developed into a project and possibly a new business area for Aker BP in the future, that is, assuming that we can establish a viable business case.... As you of course know, Aker BP has embarked on the development of a large portfolio of NCS projects, and we are eagerly looking forward to delivering these significant projects, which will unlock around 770 million barrels of oil equivalent and boost our future production. Between now and 2028, this will require the investments of approximately $20 billion pre-tax, corresponding to around $3 billion after tax. This CapEx estimate has remained unchanged since we submitted the PDOs to the Norwegian authorities approximately a year ago. We are now well on the way with fabrication and construction activities on all projects, as you can see from the short video we just showed from the Yggdrasil project, and so far, we are progressing according to plan. Today, we can also celebrate that one of our project has reached the finish line. I am delighted to announce that yesterday, we started production from the first well at Kobra East & Gekko, or KEG for short, in the Alvheim area. This is 5 months ahead of schedule. As you might be able to see from this illustration, we have drilled 4 multilateral horizontal wells, with a total reservoir exposure of approximately 42 kilometers in a relatively thin oil zone. In drilling terms, this is very high on the complexity scale. Our drilling alliance, consisting of our own drilling team, along with our partners from Odfjell Drilling and Halliburton, have delivered superbly once again. KEG adds about 40 million barrels of reserves to the Alvheim area, and together with the ongoing Tyrving project, it contributes to extending the lifetime of the field to 2040. This means increased capacity utilization for the FPSO, resulting in lower cost and lower emissions per barrel produced. As a result of what, what I would call excellent project execution and extremely high drilling efficiency, the project was delivered below budget, and the estimated break-even oil price for the project is now just above $20 per barrel. All four wells are planned to start producing before year-end, and we expect KEG to contribute about 20,000 barrels of production next year. In sum, I'm extremely pleased with this achievement and would like to express my gratitude to the project team and our drilling and subsea alliance partners. Thank you so much. So the project team at KEG has delivered an impressive performance, and as I mentioned earlier, we are also well on the way with the construction of other projects. Delivering these projects is an essential value driver for Aker BP. Therefore, we have invested substantial time and effort into developing a project execution model that drives quality and efficiency. This quarter, along with our alliance partners, we have continued to make progress, and important project milestones have been achieved. The major contracts have been placed, and we've now started fabrication activities at multiple sites. Yard capacity and rig capacity has been secured. In terms of investment and procurement, we are naturally impacted by the inflation observed across the economy. This is why we made a significant effort to understand and estimate the inflationary pressure in the various parts of our value chain before making the investment decisions. Now, nearly one year later, we see that some parts have become more expensive and some parts have become less expensive, and overall, our estimates still hold well. To sum up, we are progressing according to plan, and our total CapEx estimates, including the estimates for 2023, remain unchanged. Let's also take a quick look at our exploration activities. We had an active, and I would say, rather successful first half of 2023, and this continued into the third quarter. Of the four wells completed in the third quarter, we participated in two discoveries, Carmen and Norma. Both are interesting discoveries near existing infrastructure in the North Sea, and both are recent farm-ins with 10% interest net to Aker BP. At Rondeslottet, we had to halt drilling operations before reaching the reservoir due to well bore stability issue. The partnership is now assessing the possibilities of drilling the well next year. The high exploration activity will continue into the fourth quarter, with seven wells planned across the North Sea and Norwegian Sea. Alongside the ongoing Ofelia and Surtsey wells, we plan to revisit some recent areas of success with the Frigg Gamma Delta well in the Yggdrasil area and Storjo Vest in the Skarv area, as well as test new structures in proximity to existing installations. Please note that, as always, the timing of each well is indicative and subject to rig arrivals, and some wells have already been moved to the 2024 program. I wouldn't be surprised if that number increased. Nevertheless, we are looking forward to promising exploration activities in the coming months. Thank you, Karl, and good morning to all of you. I'm very happy that we put behind us another quarter of strong financial performance with increased income, good cost control, resulting in high cash generation. The increase in income was driven by higher commodity prices, which overshadowed the impact of reduced production quarter on quarter due to maintenance. In terms of capital spend, our projects are progressing well. Investments are in line with the estimates we provided at our strategy update in February, and our operating costs have been maintained below initial guidance. For the third quarter, this in sum translated into a cash generation of $1.2 billion, further improving our financial flexibility. I will now, as normal, go through some of the key elements of the quarterly results before ending with an update on the guidance for the rest of the year. Starting with a short breakdown of revenues. We observed opposite movements in the two main components of our income in the third quarter. Realized prices increased with 12%, which was partially offset by a 6% decrease in production. Net of the two, resulted in an increase in total income from $3.3 billion to $3.5 billion quarter-over-quarter. Realized liquid prices increased with 14%, up to $88 per barrel. This was driven both by a boost in Brent prices and strong price differentials across our crude qualities. On average, we realized approximately $2.8 per barrel above the average dated Brent in the period, where roughly two-thirds can be attributed to strong price realization on the various blends, and the rest is mostly timing effects. At the start of the fourth quarter, we continued to observe a tight physical market and a high demand for our crude qualities. If we then move on from sales and continue to the other elements of the income statement, production costs were stable quarter-on-quarter, around $250 million, as the uptick in maintenance activity and associated costs in the third quarter were offset by lower shipping and handling costs and environmental taxes due to the lower production volumes. However, this increased the cost with $0.40 on a per barrel basis, up to $6 per barrel of oil equivalents in total. As planned, our exploration activity remained high during the quarter, but compared to the previous quarter, we recognized a larger share of the spend as direct expenses. This was primarily driven by dry well costs associated with the Krafla Midt Statfjord and Rondeslottet wells. Depreciation was down this quarter, both in absolute terms and per barrel. This was as normal, driven by lower production volumes and variations in the production mix, but also by increased discount rates, which technically reduces the net present value of future abandonment cost, and hence also reduces the corresponding depreciation element. In sum, this led to an operating profit of $2.6 billion. With increasing oil prices, we avoided impairments of technical goodwill this quarter, and the tax rate returned to a more normal level of 77%, leaving us with a net profit of $588 million. Now, let's see how this translated into cash flows this quarter. We maintained steady operating cash flow before tax at approximately $3 billion, which is similar to previous quarters this year. However, as taxes are paid every second month, we made only one tax payment in the third quarter, resulting in a spike in operating cash flow compared to the second quarter. On the other hand, we increased cash flows to investments to nearly $1 billion, in line with the ramping up of fabrication and construction activities across our project portfolio. In sum, our free cash flow for the quarter reached close to $1.2 billion, one of the strongest results in the company's history. We distributed around 40% of this to investors through dividends and interest payments, and our dividend distribution of $0.55 in the quarter was in line with the full year guidance of $2.2 per share. After deducting distributions and other financing activities, we ended the quarter with an increase in our cash position from $2.7 billion to $3.4 billion. Now, before we look at our financial position, let me also give you an update on our cash tax payments going forward. In this quarter, we made the first tax payment for the fiscal year 2023 of around $860 million. In the fourth quarter, tax payments will increase as we had payments due in both October and December. Given that commodity prices have developed more favorably than we forecasted when the tax installments were determined in June, cash flow and profits will increase, and the tax payments for the fiscal year 2023 will also therefore be higher. We opted then to make a voluntary additional tax payment of around $500 million in October, which is just simply put, prudent cash management. This comes in addition to the regular installment of around $1.6 billion in total in the fourth quarter. Remaining tax for the fiscal year 2023 will then be paid in the first half of 2024, as usual. This chart, this chart on the slide illustrates how the payments might look, assuming sensitivities for $80-$100 oil price, gas price of $13 per MMBtu, and an exchange rate of 11 Norwegian kroner per dollar in the fourth quarter. The size of the remaining installments will then be revised to match the actual results when we enter into 2024. Now, let's examine the key figures related to our financial capacity. In Q3, we improved our financial position once again. Our leverage ratio, which measures our net interest-bearing debt against our 12-month EBITDA, remains stable at around 0.2. In addition, we have substantial liquidity available with combined cash and undrawn bank facilities totaling $6.8 billion. This creates a comfortable buffer against our after-tax exposure of around $3 billion of our total investment program. Maintaining a strong financial position is essential for our long-term success, and it is the foundation that enables us to pursue investments in profitable growth, while at the same time deliver on our distribution policy of providing a resilient and growing dividend. The board has resolved to pay a quarterly dividend of $0.55 per share, also in the fourth quarter, bringing the total payment in 2023 up to $2.2 per share. This translates into a total increase of 10% from 2022, which is twice the minimum ambition and in line with the plan at the start of the year. Now, before leaving the word back to Calle, let me then round off, as promised, with a summary of our expectations for the rest of the year. Today, we're making three adjustments to our 2023 guidance. Firstly, we have narrowed our production guidance to a range of 455-465 thousand barrels of oil equivalents per day. This update increases the midpoint estimate and reflects reduced uncertainty, given that we have more visibility with maintenance season behind us and only one quarter left of the year. We expect an increase in the fourth quarter production as several assets are returning to full operation following maintenance work. But to achieve the high end of the production estimate, we will need to see production efficiency exceed normal expectations across our portfolio, including a strong ramp-up on KEG, which has just started its production this week. Secondly, we further lower the production cost guidance range to $6-$6.5 per barrel, down from $6-$7. Good cost control, sustained high production, a weak Norwegian kroner versus the US dollar, and lower power prices are the primary drivers for this reduction, which I believe is in line with the communication from the previous quarters. And thirdly, we expect our abandonment spend figures to be closer to the high end of the range, and thus update our guidance to roughly $200 million. This is mainly driven by acceleration of plugging and abandonment work at Valhall Hod from 2024 to 2023. Finally, we make no changes to our estimates on CapEx and exploration spending. Thank you, David, and let me quickly recap. Our operational performance in the quarter was good, with a production of 450,000 barrels of oil equivalents per day, with low cost and as the industry leader on low emissions. Our project developments are on track, and we have now started fabrication activities on multiple sites, while the investment estimates remain stable. I'm both proud and pleased to see that the production from Kobra Gekko at Alvheim starts five months ahead of plan. We also report a strong cash flow in Q3 and for the full year, and we do some positive adjustments to the production and OpEx guiding. We will now take a short break before we open the Q&A session, and if you want to actively participate in this session, please enter via the Teams link provided on the webpage. If you just want to listen in, please stay right where you are, and we'll be back here in a couple of minutes. Hello, everybody, and welcome back. I hope you had a good break and got a cup of coffee or whatever. Now we'll start the Q&A session, and for those of you who want to ask questions, we'll greatly appreciate if you turn on your camera. As usual, Kjetil Bakken will run the queue, and by that, Kjetil, it's over to you. ... Yes. Thank you. Then the first question is from Teodor Sveen-Nilsen. Two questions. First, on production going forward, Sverdrup is definitely performing very well now. Should we expect the current run rates to be representative for the 2024 production, i.e., as you flat Sverdrup production over the next year or so? Second question is on inflation and, Calle, you explained that some parts had gone up, some parts had gone down in your project portfolio. Just wondering if you could shed some light on which parts has gone up and which parts has gone down. And, my final question is on 2024 CapEx. We've all seen that you started the steel cutting and we expect, of course, higher CapEx going forward. Is it possible to quantify how much higher CapEx we should expect over the next few quarters? Thanks. Thank you. I think that was three questions rather than two questions, but okay. Good to see you back. Sorry about that. Let me start with production. First of all, we really appreciate, and I think we all understand that the performance from Johan Sverdrup these last couple of quarters have actually been exceptional. Going forward, we actually expect the performance on Johan Sverdrup to continue, and then we'll let the operator comment more on the mid- to long-range expectations for Johan Sverdrup. When it comes to inflation, yes, there are, of course, a number of elements that goes into these estimates, but there are a couple of points I think it's really important to understand. Mm-hmm. So when we made the final investment decision back in December last year, we did a pretty deep analysis of the different elements, trying to understand where the inflation would come, how it would come, et cetera, et cetera. That analysis has been pretty spot on. So that means that, for example, like, I'll do a couple of examples without actually diving down. Steel prices is reduced from the initial assessment back in December, some hour rates have gone up, et cetera, et cetera. But from an overall perspective, I think we're, we are pretty happy with the assessment we did back in December. Now that we've placed almost all the contracts or all the contracts and placed almost all the orders, we have a much better understanding of how this will develop going forward, and much better confidence in those estimates going forward. I think that should give at least confidence in the analyst market that a lot of this is now well understood. On 2024 CapEx, David, you wanna comment on that? Yeah. Teodor, we don't plan to guide on 2024 today, but we do expect, since the projects are progressing as planned, that the best estimate still stands as the one that we provided at the strategy update back in February. And I think if you use a ruler on that graph, it's, I think we're somewhere around $5 billion. Okay, great. Thank you. Thank you. The next question comes from Sasikanth Chilukuri at Morgan Stanley. Please go ahead, Sasi. Hi. Thanks for taking my questions. I had two, please. The first was again related to Johan Sverdrup. I'm conscious you're not the operator, but I was just start trying to understand what you could say. I mean, when you look at the 3Q results, the implied gross productions derived from that implies around 780,000 barrels of oil equivalent per day. I was just wondering what the contribution of gas was in this, how the oil production compared to the guided peak production of 755,000 barrels per day? In the report you mentioned three production wells have been added this quarter. I was just wondering if these the figures already incorporate these three production wells, and there's another one expected to start in 4Q. So I was just wondering, again, adding back to the question, the last question, what should we expect? Should we expect actually production to increase? The second one was on, Edvard Grieg and, Ivar Aasen, there is a reduction in production, highlighted, as due to natural decline. I was just wondering if the decline rate seen in 3Q is indicative of the, underlying decline rate for the future as well. Just wondering if there was any guidance of the decline rates here until Hanz, Solveig Phase Two and Symra start up? It was a bit difficult to hear you, Sasi, but, I'll try my best. So on Johan Sverdrup, if memory serves me right, I think the gas contribution is roughly 5% in terms of total volume. So it's not necessarily a big gas contribution to that total production volume. These infill wells, when they come in, they actually have a good production potential. We're probably talking in the range of 30,000-50,000 barrels per day. So there's nothing wrong with the well potential and the well hopper is full for the next couple of years. So there are kind of continuous well coming on stream. And then of course, the facility is running at peak infrastructure capacity, which means that we should not expect an increase in capacity, even as new well start come on stream. This is more a discussion of distribution of production aerially on the field rather than increase in production. And then on Edvard Grieg, yeah, a couple of points. I mean, we have just gone off plateau on Edvard Grieg, and of course, the percentage-wise decline on any field is actually biggest in the period of time where you just went off the plateau, right? It's not a linear curve, it's a curve where it actually has a really high derivative. A bit nerdy, I'm sorry about that. In the early phases, and then drops off. And then, we are actually also drilling infill wells on Edvard Grieg to combat this decline. And you talked about the ramp-up of tie-ins, but we're also rerouting and remodifying the production mix on Edvard Grieg by adding more Solveig volumes, for example. I mean, this is just run of the business. This is what we do in Aker BP. This is what we're good at, is to actually fight that decline. And if you want a good example of that, I think you should look to Alvheim, where we've had this discussion ongoing now for quite a few years, actually. Sounds good. Thank you very much. Thank you, Sasi. Now, the next question comes from Yoann Charenton from Société Générale. Please go ahead, Yoann. Thank you. Good morning, everyone. So I will have two questions. One is on your CapEx estimates that have proved to be broadly stable overall. Can you please touch upon the share of CapEx that is sensitive to changes in the USD NOK rate? And can you please provide some color on the associated items so that are the most sensitive, basically, to this USD NOK rate? So is that the first sort of question. Then I would like to look at, basically, if you don't mind, the Alvheim production hub. It looks like the turnaround in the third quarter was pretty comprehensive, given its impact on production. So I'm willing to better understand to which extent does this turnaround explain this earlier startup of KEG? Is there basically technical or reservoir-related reasons for bringing forward the KEG startup by several months? Yeah. So on the CapEx estimate and the NOK-denominated or USD-denominated cost, I think the underlying exposure is probably in the range of 2/3. So 2/3 NOK and 2/3 foreign, but that doesn't necessarily mean that's our exposure. What is the actual underlying exposure is a bit more complicated because you could end up in situations where Norwegian providers are buying goods or services that are also paid for in euro or USD. But it's on our hand, it's roughly 2/3 NOK, and that's because of the high degree of Norwegian vendors in these projects. I think that's a good, it's a good benchmark to use. Would you agree? Okay. And then on Alvheim, yes, the turnaround was pretty comprehensive. So we opened up pressure systems, gas drying systems, et cetera. Of course, this is a part of an ongoing maintenance program, where maintenance intervals are scheduled in time, and they're usually between 2 and 4 years, and now we had one of these 4-year stops. So you're absolutely right, it was pretty comprehensive. And then the startup of KEG is not in any way actually related to the turnaround. What this is, is basically stellar drilling performance. When we planned Kobra East & Gekko, which is four 3-branch multilaterals with more than 42 km of reservoir exposure, we did that at what we call a P25 level. That is what we planned the performance to be among the 25% best wells drilled on the Norwegian Continental Shelf of this type. What we realized is probably more like P5 performance. So the whole early startup is actually explained by much more rapid well delivery, and we've broken several records while we're doing this. And yeah, without the Alliance Model, this wouldn't have been possible, and we certainly would not have been able to relocate surface and subsea installation without the Alliance Model. So this is, this is pure performance. It's not related to the turnaround on Alvheim at all. That's very clear. Thank you. Thank you, Johan. Then the next question comes from Mark Wilson, from Jefferies. Please go ahead, Mark. Okay, thank you. Good morning, and, I congratulate you on the style of your presentation. I think we're gonna have to get the robot dog into one of these future ones. You need to get that, that boy out there again. I'd like to ask about exploration. You've got the 7 wells in 4Q. You talked about Rondeslottet and, potentially going back to that in 2024. The 4Q wells, they all seem like smaller tieback-type projects. Could we just confirm that? And then if in success case, and then outside of a potential return to Rondeslottet, are there any, greenfield targets that could potentially be drilled in the coming years? That's the first point. And then to tie in that, could you just give us an update on the discovery you made in the Yggdrasil area, that was gonna be included into that development, I believe, and how that hasn't added to the CapEx overall? Thank you. Okay, excellent. Yes, I can confirm that the remaining ILX, or the ongoing drilling program on exploration is ILX. And as you may recall, Mark, we have actually been out there saying that about 80% of our exploration spend will be focused on these ILX projects. And the reason for that is simply that these represent really high value. It drives up performance on our hubs, it is a short time from expenditure to realized value. And as new technology is coming to the market, we're also actually seem to increase the value quite significantly. Case in point being the recent start-up of Kobra East & Gekko, where Kobra was actually discovered quite a few years ago. I think the biggest one in 2024 is actually also maybe not a tieback. It's Deep Alvheim, which is a high-pressure, high-potential gas field below the main Alvheim reservoir. I would say most likely development scenario is tied back to the Yggdrasil area and not the Alvheim area. But apart from that, the 2024 program, which we will present in February, I think is on par with what we've done in the past. So I think you should expect more of the same, but probably even higher valuation and even higher chance of success. Then on East Frigg, Epsilon, and East Associated, we've actually already done a DG0. We've started to plan for field development. And the way it looks now, I assume this will end up as a plateau extender on Yggdrasil. And it seems that we, we will be able to kind of mix this into the field development that's ongoing at Yggdrasil with the current pace. And we'll also drill a new Geopilot on the main Frigg Gamma Delta field to confirm the observation we saw on the flanks with higher flank volumes and better reservoir qualities, just to make sure that we capture all this data before we go into production drilling. Maybe I can just add regards to, to CapEx on, on Øst Frigg. So, so of course, given that we've already put a lot of infrastructure in place on, on the Yggdrasil, it's meant to cater for, the upside potential in the area. And that means that the additional CapEx will be quite limited, but we'll come back to that, most likely in February when we have the, quarterly results and the strategy update, where we'll also guide on the, on the forward-looking CapEx more thoroughly. Yeah. Okay, got it. So we should just consider that to be an add-on to the main development? Absolutely. And remember, when we talked about this back in December, I think we already stated that approximately just half of the well slots that are being installed are actually being drilled as a part of the main field development campaign, right? So, it's almost this is what we expected when we made the Yggdrasil commitment, and it's a part of the field development. We're just rushing it a bit now to make sure that we've got one continuous drilling line and not to start and stop. Okay. Thank you very much. Thank you, Mark. Next question comes from Victoria McCulloch from RBC. Please, Victoria, go ahead. Morning. Thanks very much, all. I'll stick to a couple from me. So you touched on unplanned maintenance in the presentation. It's not probably something we've talked about for a while. How often does unplanned maintenance happen across the asset base? You know, should we think about that as something when we look at Q3 going forward? And then I appreciate you're not operator of Sleipner, nor am I asking you to increase or to be explicit about reserves. However, in your longer-term production guidance, you know, is it purely the published reserves for Sleipner that make up your, the production figures in your long-term chart that you provide with the growth? How much of the reserves are in your production guidance at the moment, given I think there's about 25% of reserves being produced to date? Obviously, the plateau is higher and appears to be potentially longer than when the field was sanctioned. I'm just interested in your color on it at this stage and what's included in your numbers. Okay. So let me start with unplanned maintenance. This is something of course that we don't want. And every unplanned maintenance represents some sort of event. And I think this is actually a key part of our improvement program, and you can actually monitor it if you go back and look at our performance on production efficiency. So it's been steadily going down. I think we planned this year for about 91%-92% production efficiency. We had a little higher than 95% until this quarter, 99% in this quarter. So if we have the same performance in Q4, we're probably back to around 93%, which actually will be really, really good from an industry perspective. My assumption, looking at the KPIs of the different assets, is that the backlog on maintenance is going down, the tier three, tier four KPIs that indicate that you might have a maintenance issue or an integrity issue is certainly going down. We're having much fewer inspection finds that indicates that the health, so to speak, of the assets is improving significantly. We are planning internally performance on the same level as we saw in 2023, also for 2024. I think that would not be a bad assumption. And then that being said, when you have these events, it's also about how good we are restoring production, and here we've also seen a significant improvement in the last couple of years. And since you asked the question, I would take the opportunity to actually commend the Aker BP organization, because there's been a significant improvement in how fast we are now restoring production, even if we have these events. So that's also something that is, let's say, improving production efficiency, even if we, as a point of departure, do not really want these unplanned events. I'm not sure I understood your question on Johan Sverdrup, but of course, the planned reserves that are communicated by the operator, that is the total reserve estimates, is of course, included also in our production curve. But on top of that, we also included our assumption on what will come of new wells that are not necessarily in the reserve category, but might be also in the IR category, in the long-range profile. Now, for the next couple of years, this is not necessarily a big topic, as most of this has now either been decided or are part of the PDO scope, et cetera, et cetera, which means it's classified as reserves. So, if you're wondering how much of the future production from Aker BP that's classified as reserves in Johan Sverdrup, I would probably say that's close to 100%. Okay, that is, that's what I was looking for. Thanks, that's helpful. All right. Thank you, Victoria. Then the next question comes from James Carmichael of Berenberg. Please go ahead, James. Hi. Morning, guys. Just a couple of quick ones, please. I was just wondering, maybe you touched on this in the presentation, I might have missed it, but could you just give a bit of color on the reduced opex guidance? How much of that is sort of FX effects versus actual performance? And then just on the additional tax payments you've announced in Q4, you know, that's obviously, I guess, shows the benefits of pricing and profits being higher than expected. So is there anything we can read from that into the dividends, the dividend outlook? You know, is it fair to assume that maybe 5% is beatable for next year? That's all for you, David. All for me, okay. Hi, James. Yeah, so with regards to production cost, so we are very glad to see that costs are under control, and we're delivering underlying costs as expected. When it comes to variations quarter on quarter, it's typically dependent on on well maintenance activity and the phasing of that, so that's always something that impact on a on a quarterly basis. And when it comes to the reduction in in guidance level, now I think that's fair to say that it's it's partly driven by by FX and then partly driven by by small underlying adjustments. But the main message is that that costs are are under control, which we're glad to see. When it comes to the extra tax payment this or in the fourth quarter, I think that's, as you say, it's a good thing, right? It means that we are observing more constructive prices and higher profits than what we expected when we set the installments back in June. Meaning that we're making more money. When it comes to dividend guidance, I think on the policy stance, our minimum ambition is 5%. With the guidance or the dividend that's been declared for the fourth quarter, we have a total increase of 10% versus 2022. And the main ambition for us is to ensure that dividends are resilient and growing over time. And then we'll come back to dividend for 2024, when we see you again in the fourth quarter presentation and strategy update. Okay. Thanks very much. Thank you, James. Then the next question comes from John Olaisen from ABG. Please go ahead, John. Yeah. Good morning. Good morning, everybody. M&A activity is high in the US at the moment, but it has not fully arrived in Europe. I got a couple of questions related to that. One, maybe do you expect that we'll see more consolidation of the European E&P players, the smaller and bigger? And secondly, have you noticed any change in international oil companies' interest in Norway in general, one way or another? And finally, the Chevron CEO was apparently quoted saying that there are too many CEOs per barrel of reserves. Do you think there will be any advantage with fewer players in Norway, or are there already too few, right-sized? I love your questions, particularly the last one. That's almost like a meta question. So M&A activity, I think I've been quoted previously saying that I expect consolidation in this industry. And I think as usual, the U.S. onshore and U.S. players are running ahead of the Europeans. So that being said, I think we should expect consolidation also in Europe, and elsewhere in the world. And I think that will happen actually on all the scales. I think it's much more difficult now to run a small, small cap or EMP company with all the volatility and the pricing discussions and all that that's going on. I think you yes, I think you should expect consolidation also in Norway. Whether we've noticed any as an increase in interest in Norway... No, not necessarily. I think people are looking at getting more what they already have. They're looking at high grading and taking out synergies. They're looking at what kind of size advantages they can have, et cetera, et cetera. So it's the classical, I would say, M&A questions that are now being played out. And then your question, are there too many CEOs per barrel of oil? Yeah, I actually think so. But I think it's making a couple of points, actually. The one is, of course, how many players there are in the market, and every player has a CEO, so it's kind of like a meta question. And I think that's correct. And then second, I think there is something to be said about the productivity in this industry. Again, I think I've been quoted on this quite a few times. We are not necessarily good running up productivity, which means that if you think about this from a synergy outtake perspective, there's still significant value to be had, which is also, of course, driving up the interest in an M&A. If we've been significantly better in driving up productivity on, probably on par with the onshore industry, there would not have been this amount of synergies to be taken out, and then the M&A activity probably been a bit slower. Mm-hmm. And if I may, I have a follow-up on all this. It seems like you're expecting consolidation, both in terms of among different asset class, sizes of oil companies, and also in Europe, and also potentially in Norway. And then, my final question, and wrap up to that: How will Aker BP be positioned in this? Will you actively trying, be trying to do consolidation, or you will, will you be waiting until somebody potentially approach you? I don't think we're very known for waiting, John. But what I'm saying that, I think I've said this also before, that I haven't been in this company one day in the almost 10 years I've been here, that we haven't had an ongoing dialogue in some way, shape, or form about M&A, and that comment still stands to this day. But again, we're extremely disciplined. We have the lowest costs, we have the lowest CO2 per barrel, we have the lowest breakeven in our hopper. And there is no way that I'm going to jump on an consolidation wagon and abandon that view on productivity, on value creation for our investors, just to be a part of a growth story. Yep. And my final, final question on that, are you reiterating that Aker BP will be 100% Norwegian in production based? Norway, Aker BP is a Norwegian pure play, proud oil and gas player. Sounds good. Thank you for taking my questions. Thank you, John. Then the next question comes from Anders Rosenlund of SEB. Please go ahead, Anders. Yes, thank you. Is the Sverdrup oil sold at a premium or a discount to the Brent price, and has this changed? You wanna do that? Yeah, no, I can definitely do that. Okay. As I mentioned in my part of the presentation, we've seen strong differentials across crude qualities, this quarter. I think on average, we've stated that we typically realize Brent. But I said that the average was roughly $2.8 per barrel above Brent, this quarter. And Johan Sverdrup has been one of the crudes that's been performing quite well recently and been trading above Brent. How that will develop going forward is always difficult to project, because it has a lot to do with the different dynamics, of course, across many different geographies. But we definitely see that there is a high demand for our crude qualities, which is something, of course, that we're very happy about. And then I also, of course, have to commend the trading team, who is doing an excellent job on marketing our barrels. Thank you. Thank you, Anders. The next question comes from Lydia Rainforth of Barclays. Please go ahead, Lydia. Thank you, and good morning, and sorry for the video quality. I, I'm in transit. Two questions, if I could. Can I come back to the safety record? And clearly, it's very good relative to a number of countries, companies across the industry. But you did talk about sort of not being comfortable with it, and as activity ramps up next year, how do you think about the improvements that you need to make there? And then secondly, if I can just pick up on something you talked about earlier, about the productivity side and not being as, not being able to make the improvements in productivity that we've seen onshore. What do you think are the biggest gaps there for productivity? Thank you. Yeah. So let me start with safety. So the safety figures that we are presenting now is mostly related to personal injury of a minor qualification, right? So it's, there are no major injuries, there are no major process safety events. I can't remember the last time we had a major safety incident. But my point is more that, we, as an organization, have defined that everybody that's coming to Aker BP to work, whether they are a part of Aker BP, they're working for Aker BP, or they're working for one of our alliance partners or contract, they should go home in the same or better state than they came. That means that to me, every incident we have, where people are being injured, is something that should be avoided. I think it's a very strong drive in the organization that safety is our priority number one, and it's something that we really do look after. That means that as even minor injuries trend up, we are, of course, implementing actions to correct that event. Now we have a relatively controlled, I would say, activity set. As we're ramping up activity across multiple sites and further down in the value chain, we need to project the same expectations to safety standards as we have in our own operations. That is a zero, it's a zero injured personnel standard, right? So that's the point. I think the safety program and activity is actually working. It's just that we need extra focus on these personal injuries and to roll back that trend. And then on productivity, I think it's the... Yeah, the way I view this is that the oil and gas industry is almost like a risk management business, right? So when you actually make a big discovery, and if it's big as Johan Sverdrup, then cost and productivity is tier two, tier three, tier four events, really. It's not really top of mind. That means that we have a tendency in measuring output metrics, like free cash flow, like oil production, et cetera, rather than actually measuring the amount of services, man-hours, personnel that goes into executing a single job, right? I think right now, there's a multitude of issues. It's about planning and how we actually do plan, and how do we actually meet plan attainment. It's about logistics, it's about IT costs for the moment, right? With all these new IT tools coming up, it's... But it's also about how we execute everyday tasks, right? How much of, let's say, the technology and the capability that are out there in the market, are we, as an oil and gas company, embracing, and how much are we replicating, and how much are we actually redoing? And I'm challenging the organization, saying that we shouldn't really develop something if there is a tool out there that actually do the job just because we're an oil and gas company and because we have the funds to do so. And then, I think it's a good example of where productivity has actually gone up is drilling in wells. Where you've seen this measurement and this focus, not necessarily on day rates, but on meter per day, on quality of wells, et cetera, et cetera, which have driven a host of interventions and activities, and actually resulted in significantly lower drilling costs and significantly increased performance. And case in point maybe being the current, or probably the best case actually, being the current performance on KEG. If we could do that across all the disciplines involved in oil and gas production, we would be significantly better than we are today. Brilliant. Thank you. Thank you, Lydia. And, the next question comes from Matt Smith from Bank of America. Please go ahead, Matt. Matt, you have to unmute your phone. Okay. Morning, guys. A couple of questions from me, please. The first would be, coming back to the comments on CapEx inflation. You, you say there's sort of been pluses and minuses, and I guess I just wanted to ask whether these, the pluses and minuses have been in the right areas for Aker BP, and I guess I'm just sort of reflecting on your comments around open book principles and your contracting strategy, back at the last, strategy update in February. So any sort of comments around your relative exposures there, and how you sort of see that strategy and the success of that strategy playing out so far, I'd be interested. And then the second one from me would just be following up on John's question, really, you know, if Aker BP is going to continue to be involved in this trend of consolidation, and Aker BP is, so far, a Norwegian pure play. I just wondered whether you sort of saw any limit to growth within the region, whether that's to do with how tightly held assets currently are, how consolidated the industry already is, or from a regulatory perspective. So I just wondered if you saw any ceiling to grow in Norway as Aker BP. Yeah. Okay. Thanks, Matt. On CapEx, and particularly commenting on this open book or POs approach. So that is tightly linked to, one, risk management in the value chain, and two, the Alliance Model that is now being run. So far, I would say that the amount of open book purchases we've done is a bit lower than I expected in the second quarter. There is actually now more... There seem to be more resilience than we expected, which means that we have actually increased our fixed price percentage compared to what I expected in the last quarter. And that's not because we decided, it's because our vendors would like it that way. It probably has to do with conservatism on their side, but it's also more like the kind of practice on quite a few of it. But it also reflects that they are now able to go out in the market and place longer fixed price orders to their sub-vendors. So I think the open book principle actually worked out fine. We are seeing a much more open dialogue. We understood significantly better the price creation on these packages, and we're better suited to understand and implement mitigating actions where we see that there might be kind of quality incidents or quality challenges, or it might be procurement challenges down in the value chain, et cetera, et cetera. So it actually works out pretty well. I say... And then I don't think it with the amount of contracts we're putting now, I think on the second vendor line, we're 2,228, if memory serves me right, vendors. To go to all of those and expect a fixed price, that would not have been realistic... and could probably not have been done actually. And then limits to growth, yes, we are in Norway. So there are certainly physical limits to growth. It's probably not worth expecting that we'll take over major part of Equinor's operations in Norway. But there are quite a few interesting targets and interesting assets yet to explore for Aker BP. But as I've said, we will be focused, and we'll be, we'll target the opportunities where we see that this could be value creative for Aker BP shareholders, given our operational performance at the moment. Perfect. Thanks very much, guys. Thank you, Matt. Looks like we have a follow-up question from Mark Wilson from Jefferies. So Mark, please go ahead. Yeah, it's just you've got a slide on the realized prices that's quite interesting, and with oil showing resilience coming back and obviously gas off the incredible highs last year. What is your view of the gas evolution through the coming winter, and how do you plan to protect both moves either way? Gas pricing? Okay, I can do that. You can have a crack at it. Yeah. If I'm not happy, I can do it, too. And then you can correct me, what David meant to say. Well, no, I think that's a good follow-up, Mark, so thank you for that. When we are selling our gas at spot. Basically, two-thirds going to Europe, one-third going to the UK, and that's been our strategy through the past few years, and that's also the strategy that we have going into winter. So you should expect market pricing from Aker BP on the gas side. And then, I don't know, Karl, if you have any follow-ups with regards to your projections on price development. I know you like to speculate on oil and gas prices. Yeah, yeah, I love to do that, because I'm so good at it, actually. No, I think I'll, I think I'll avoid doing that. But, I think it's worth well noting that the storage in Europe is now almost full. And it's a significantly better situation. If you asked me a year ago where we would've been going into the winter of 2023, 2024, I would've said that this would probably be quite a problematic winter. Right now, I think that we have, or rather the European energy market is balanced in supply-demand. And the step up of LNG has been actually amazing, compared to what we projected. So I don't think you should expect a repeat of the extremely high gas prices this winter that we saw last winter. I think this will be more muted and more normalized, but I expect prices to be higher than in the situation before the Ukraine war, obviously. Thank you very much. Thank you, Mark. Then the final question of the day comes from... Yeah, the final, final question comes from Kate O'Sullivan from J.P. Morgan. So hopefully, Kate, you are on the line. Unmute her. Looks like you're muted from our side. There seems to be a technical issue. So, Kate, let's take that bilaterally after the call. So that means that it is a wrap, guys, and thank you so much for listening in. I know that you are busy, and I appreciate all your questions and comments. And with that, I think we'll say have an excellent day and a safe day.