Good morning, everyone, and welcome to this presentation of Aker BP's second quarter results in 2023, which will be given by CFO David Tønne and myself. After the presentation, there will, as usual, be a Q&A session. It is a true pleasure to report a very strong quarter for Aker BP. We produced more oil and gas at lower cost and with lower emissions than ever before in the company's history. I am also pleased to report that our field developments are on track. We are off to a good start for the project that we launched in December, with important milestones achieved in the quarter, including government approval of all PDOs. We've also had recent exploration success with a significant oil discovery in the Yggdrasil area, and also participation in the Carmen prospect. On the financial side, we've further optimized our capital structure through successful transactions in the bond market. As I've said before, this was an eventful quarter, and what makes me most proud is the dedicated team with a company culture for operational excellence and continuous improvement that really makes Aker BP an E&P company for the future. Aker BP delivered excellent operational quality this quarter, and once again, we set a new production record. We produced 481,000 barrels per day in Q2, which is 6% above last quarter and 17% above third quarter last year, which was the first quarter as a combined company with Lundin. The production increase is mainly driven by the ramp-up of the Johan Sverdrup field. This strong performance has allowed us to increase our production guidance for 2023, which David will cover in more detail towards the end of our presentation. Phase two of the Johan Sverdrup development was completed at the end of last year. After a couple of months of ramp-up, production stabilized at the design capacity of 720,000 barrels per day. In parallel, the operator, Equinor, worked on debottlenecking the facilities. In May, we successfully tested the capacity at 755,000 barrels per day. We've been keeping it steady since. With our 31.6% interest in this world-class field, Johan Sverdrup is the main contributor to Aker BP's new production record in the quarter, and the field now accounts for roughly half of our production. Johan Sverdrup is also an important driver of our re-record low unit cost and emission intensity. Perhaps the most important performance indicator for operations in Aker BP is production efficiency, which in reality measures the capacity utilization across our operated assets. This performance metric has been consistently strong the last 12 months and was as high as 96% in the second quarter, up from 93% in the first quarter, as we experienced no planned or unplanned interruptions. This high efficiency also translate to lower unit cost. In Q2, we operated a record low unit cost per barrel of $5.6 per barrel, down from $7.2 per barrel in the previous quarters. This reduction is caused by a combination of factors, including high efficiency, just mentioned, and also by lower well intervention activity and a weakening of the Norwegian kroner, which is the base currency for the majority of our OpEx. With such a strong first half of the year, we today announced a lowering of our full year estimates by $1 to a range of $6-$7 per barrel. It is, of course, a fundamental goal and a top priority for us to keep our people safe. As I've said many times before, we do believe that high safety goes hand in hand with high operational efficiency in general. I am therefore not satisfied with our safety performance in the quarter, where we had an increase in the number of personal injuries, pulling the TRIF indicator to 1.6. Fortunately, none of these injuries were of high severity, but the bottom line is that they should not have happened. We are, as we always do, investigating each incident to learn and to prevent it from happening again. Q2 was a record quarter, not only on production volumes and operational cost, but also in terms of greenhouse gas emissions. We continued our progress on decarbonization, and we today reported greenhouse gas emissions of 2.6 kilograms of CO2 equivalents per barrel, down from 2.9 in the first quarter. The main reason for this good result is that an increased share of production came from fields that are powered from shore. Especially, of course, the ramp-up of Sverdrup Phase 2. With this strong performance, we are fortifying our position as a global industry leader within greenhouse gas emissions, as we've shown in the recent quarters. Compared to the 300 largest upstream E&P companies, Aker BP is ranked number one on emission intensity per barrel produced. In the previous couple of quarters, we have provided detailed information about a large project portfolio, which we will put into production over the coming years. We really look forward to delivering these great projects, which will unlock above 6, 700 million barrels of oil equivalent, and increase our daily production to around 525,000 barrels. My message today, as also was the case the last time I stood here, is that we are off to a good start, and that we are progressing according to plan. Delivering these projects are obviously a very important value driver for Aker BP, and therefore, we have invested a lot of time and effort into developing a project execution model that delivers quality and efficiency. This quarter, we have, together with our alliance partners, continued to make progress, and some important milestones have been achieved. In June, the Norwegian Ministry of Petroleum and Energy approved all nine PDOs that we submitted in December, and although this was as expected, we are glad to receive this acknowledgement. Our largest project, Yggdrasil, here, we recently passed the common system design freeze with no critical issues. This means that the design of the major area development is regarded as mature. The Yggdrasil area consists, of course, of three independent platforms, tie-ins of subsea field, onshore power from shore, and an onshore operation center, including a groundbreaking operations philosophy. For the PWP Fenris project, the system design freeze is on schedule for Q3, and the fabrication of the Fenris jacket and the pre-drill module has already started. We will now step up construction activities on all the projects. To sum it up, we are on track and keep our total 2023 CapEx estimate of $3 billion-$3.5 billion unchanged. In the quarter, we made a significant oil discovery in the heart of the Aker BP-operated Yggdrasil area, with a well-named Øst Frigg Beta/Epsilon. The volume is estimated to be between 53 and 90 million barrels, about twice as large as the pre-drill estimate. We are now working at high speed to mature this discovery to become a part of the Yggdrasil development project, which would, of course, increase the gross resources of Yggdrasil by around 10% to more than 700 million barrels. Yggdrasil is already designed, in fact, to take in such additional volumes, hence, the additional investments will be low. This means further improved profitability, extended plateau production, and increased value creation from Yggdrasil. The development concept for the Yggdrasil area includes significant flexibility and is designed to be a hub for future discoveries and fields just like this one. We see further upside in the potential around Yggdrasil, and in collaboration with our partners, we will continue active exploration in the area in the years to come. As you can understand, we are very pleased with the results of the Øst Frigg Beta/Epsilon well. There are also other aspects of this well that are worth highlighting. The well had both a vertical main track and three horizontal sidetracks. The first two sidetracks were drilled in the beta structure to prove oil and appraise the discovery. The sidetrack to Epsilon was the last one, and as we continued drilling through the structure, we saw an oil column that was consistently higher than expected. We continued drilling all the way towards the gamma structure that you can see on the left of this illustration. When the well reached its target, the team had drilled 8,168 meters, and as it made its way horizontally through the reservoir, the value of Yggdrasil increased meter by meter in what is now Norway's longest exploration well ever. The operation was monitored 24/7 from our new drilling operation center in Trondheim, and by using so-called geosteering, primarily driven by ultra-deep resistivity measurements, the team could optimize well placement in the oil-bearing layer, as well as map the top of the structure. This is what makes this exploration well unique. The team was able to utilize a combination of state-of-the-art technologies to perform a safe and excellent drilling operation, delivering Norway's longest exploration well to date. A truly value-creative operation. Encouraged by our success with the drill bit so far this year, we continue to execute on a busy exploration schedule for 2023. In addition to the oil discovery at Øst Frigg, we are also partner in the recently announced discovery in the Carmen prospect, operated by Wellesley. We are currently drilling the Rondeslottet well, which is a classic high-risk, high-reward opportunity. 20 years ago, a large oil discovery was made here, but the reservoir properties were poor, and the discoveries were classified as non-commercial. The purpose of this well is to test if the reservoir properties improve as we move up the flank of the structure. In our exploration program for the rest of the year, two operated wells have been added and one have been moved into next year. Both the Surtsey well in the Yggdrasil area and the Rumpetroll South well in the Alvheim area will be drilled in the fourth quarter, while the drilling of the Kalvfjell prospect in the northern part of the North Sea is moved to 2024. We have also added a DNO-operated Norma well to this year's program, where we have farmed in with a 10% stake. As always, the timing indications are only indications. This is a historically active exploration year for Aker BP, and we very much look forward to executing on the plan. Thank you, Karl, and good morning to all of you. As we reflect on the end of the second quarter, it also marks the one-year anniversary of our combination with Lundin. Looking back, it is good to see that the integration has been successful. We have achieved new levels of excellence across all operational parameters, and this is also reflected in our financials. The second quarter is no exception, and we are pleased to report excellent operational performance, which has translated into strong financial results. We have successfully maintained our focus on cost control in an inflationary macro environment, resulting in both CapEx and OpEx that are in line or even better than the expectations we presented at our strategy update in February. We also continued to proactively optimize our capital structure, and through bond transactions in the quarter, we have strengthened our financial capacity and extended our debt maturities. Thereby, we have achieved a better alignment between investments and financing in the years ahead. Now, let's take a closer look at the actual results. Of course, we will start with the drivers behind our revenues. Total income ended at $3.3 billion, in line with the previous quarter. Listed volumes increased by 27,000 barrels per day, mainly driven by the increased production level at Johan Sverdrup. This was offset by lower realized prices, which dropped by 8% from the 1st to the 2nd quarter, mainly driven by natural gas, which dropped by 35%. If we zoom out to the full income statement, here we can see that even with a significant increase in production volume, we managed to keep costs lower than in the previous quarter. This can be attributed to a combination of factors, including lower well maintenance activity, a continued weakening of the Norwegian kroner versus the US dollar, and lower power prices. This also had a noteworthy impact on the unit cost, resulting in a record low $5.6 per barrel produced for the quarter, down from $7.2. This significant reduction can also partly be attributed to the increased production from Johan Sverdrup, which has the lowest operational cost per barrel in our portfolio. Exploration spend in the second quarter was $91 million. As the majority of this was related to the discovery wells at Øst Frigg and Carmen, and therefore has been capitalized, the exploration expenses in the P&L were only $27 million. EBITDA came in at $3 billion, slightly higher than the previous quarter. After factoring in depreciation and impairments, our operating profit amounted to $2.3 billion. The impairment this quarter was mainly related to technical goodwill on Edvard Grieg and mainly driven by lower forward prices. In addition, we also wrote down the Ve discovery from Q1, which we now consider as non-commercial. The effective tax rate for the quarter was 82%, slightly up from the marginal tax rate of 78%, and mainly due to the impairment, thus leaving us with a net profit of $397 million. If we then move on to the cash flow statement. Cash flow to investments increased to $776 million, as we are gradually increasing the activity in our field development projects. The activity level will continue to grow in the coming quarters, and we maintain our full year guidance of $3 billion-$3.5 billion. Cash flow from financing was positive at $66 million, driven by bond market transactions, which I will come back to shortly. Before that, let me round off the cash tax discussion with some forward guidance. As mentioned, we paid the final tax installment for the fiscal year 2022 in the second quarter, and as from the third quarter, we will start paying installments for 2023. Since we don't know the actual tax until the year is over, the initial installments are determined based on an estimate of the 2023 results. The installments are made in Norwegian kroner and are equivalent to approximately $825 million each. For the third and the fourth quarter, 2023, these numbers have now been fixed, and when we enter into 2024, the size of the remaining installments will be revised to match the actual results. This chart here shows how the tax installments may be adjusted under different oil price scenarios for the remainder of 2023. Now, let's move on to the bond transactions. A key priority in our financial framework is to maintain a strong financial position, and we are continuously working to optimize the balance sheet to ensure that we have the proper access to capital, not only today, but also in the years ahead. In June, we executed several transactions in the bond market. We issued $500 million of senior notes with maturity in 2028, and $1 billion with maturity in 2033. We also bought back Aker BP bonds with maturities in 2025 and 2026 for $1 billion. The effect is that we have strengthened our financial capacity by half a billion dollars, and we have extended the maturity of over $1 billion in bond debt until after the start-up of all ongoing field development projects, and hence, created a better alignment with our investment plans. The bond offering was well-received in the market, with a book that peaked with almost six times oversubscription and with credit spreads that reflect our investment-grade credit rating. We ended the second quarter with $3.1 billion in net debt and a leverage ratio of 0.22 times net debt to EBITDAX. The weighted average time to maturity increased from approximately 5.4 to 6.7 years, and our available liquidity at the end of the second quarter was $6.1 billion, of which $2.7 billion was cash. Now, everything that we do on the financing side is part of a bigger picture, where we're using a mix of equity and debt to finance our investments, which will create even more shareholder value over time. Here is one way to illustrate this bigger picture. The sources and uses graph on the left-hand side is the same as we presented at our strategy update in February. It tells an important story, which I would like to reiterate. On the bar to the left, we show the estimated cash flow from operations after tax from 2023-2028 at various oil prices. Here you see the strong underlying cash flow generation from our low-cost asset base, which is then compared to the planned uses of this cash flow. Our pre-tax investment program has a significantly smaller after-tax impact. Around $5.5 billion after tax are spent on investments, exploration, abandonment, and financing over the next 6 years, which is covered by organic cash flow at an oil price around $35 per barrel on average. Any cash flow above this is capacity for dividends and debt repayment. This cash flow generation provides capacity for a resilient dividend that grows in line with value creation while we invest in profitable growth into the next decade. To round off my part of the presentation, let me revisit our guidance for 2023. Today, we announced 2 adjustments to our 2023 guidance. First, we have increased our production guidance to a range of 445 to 470, which incorporates the better-than-expected production in the first half, with very high production efficiency across our portfolio, and Johan Sverdrup successfully reaching its new plateau level. The production run rate at the end of the second quarter was even higher than 470, we do expect a lower production in the third quarter due to planned maintenance. The new range is comparable to a P90 to P10 range, where the midpoint represents the most likely outcome. To reach the high end, we would need to see continued high production efficiency across the portfolio, including Johan Sverdrup. Good contribution from new wells that we plan to put on stream, as well as an efficient execution of the maintenance program. For production costs, we have lowered the guidance range to $6-$7 per barrel, down $1. Main drivers are here, good cost control, higher production, weaker Norwegian kroner versus the US dollar, and a normalized power price. For CapEx exploration and abandonment spend, our forecast remains basically unchanged, and hence, we make no changes here. Thank you, David. Thanks to all of you for watching. We will shortly open up for Q&A. Let me quickly summarize why I think this has been a remarkable quarter for Aker BP and put it into the context of our strategy. We delivered record-breaking performance on production efficiency and output, as well as on cost. We fortify our position as the industry leader in greenhouse gas emissions. We are on track with our large project portfolio, which will create significant shareholder value in the years to come. We made new discoveries that add to our resource base and increase the value of our ongoing development projects. We will now take a short break before we open for Q&A. If you want to participate in this session, please enter via the team links provided on the webpage. If you just want to listen in, stay right where you are, and we'll be back in a couple of minutes. Welcome back, thank you for your patience. We'll now start on the Q&A session. For those of you who want to ask questions, please raise your digital hand, Kjetil from IR will help me conduct this Q&A session in what we hope will be an orderly manner. I'm sure that we'll all appreciate if you could also add your camera on Teams if you ask questions. With that, Kjetil, who is first? Yes, the first question is from John Olaisen. John, if you can unmute, you are online. Yeah. I had to take on a little bit nicer T-shirt, being on holiday. There has been a couple of big or fairly big transactions in Norway in the first half. Vår acquired the Norwegian part of Neptune Energy, and OKEA acquired the parts of Statfjord. Just wonder for curiosity and also just to understand your thinking, could you comment whether you consider these assets? Also, are there more significant transactions ongoing in Norway at the moment? If you could comment on those two things, please. Yeah. Thanks, John. Yeah, I love your T-shirt. No, I don't want to comment on other companies' transactions. There are obviously always quite a few transactions being considered and processes ongoing, and I think I've been quoted previously as saying that there's never been a day that I've been employed in Aker BP where we hadn't had an ongoing M&A process or BD process, and that is still true. Personally, I think that you'll see more consolidation, both in the industry in general, but also on the Norwegian Continental Shelf. From an Aker BP perspective, we will be disciplined and stick to the previous strategy and only execute transactions that we believe is value creative for our shareholders, either in reducing cost, improving finances, or reducing risk. Do you have any assets that you potentially could be selling or stakes? It's a good question. I'm not, of course, going to comment on specifics, but I think it's a part of what I'm saying, that there's always discussions around BD transactions, that there are possibilities also for some sort of transactions involving also Aker BP assets. My second and final question is, regarding rig capacity. Rig rates seem to be increasing by the week, the rig availability is getting lower, we're seeing rigs moving out to Norway and now coming back to Norway with additional costs. Mm-hmm. Pretty strange move, by the way, I just wonder, in light of this, could you please update us on your secured rig capacity for the years to come, please? Yeah. As I'm sure you're aware, we have a rig alliance with Noble and Odfjell, and we've also secured rig with Saipem. As of right now, we have secured the capacity we need, both for the exploration program and for the production drilling in the PDO program. Right now, there's no need for new rig capacity in the Aker BP work program. All products. agree with your sentiment. Yeah. Yeah. Just to confirm, all production drilling for the PDO project has been secured? Yes. We have rig capacity for production. At fixed prices as well, may I ask? Well, the prices in the alliance contracts are split between an OpEx element and a CapEx element. The CapEx element is set based on a certain formula that involves also the prices that they could achieve in the market. Because the whole idea around the alliance contract is not to minimize the cost of the rig, but to maximize the performance, and thereby minimize the number of days we spend, and thereby reduce the well cost while keeping the earnings to the rig owner. Does that mean that if rig rates continue to go up from here? ... it could potentially be something, some lead to some higher CapEx on your projects? Yeah, potentially, but very limited because the in reality, this actually contributes to a smoothing of the rates in the Aker BP portfolio. I don't foresee any significant cost increase as a result of the recent market trends that you've seen on the rig side. Hmm. How about the other cost elements on your development project? We saw Aker Solutions with very strong numbers today. It seems like most of your sub-suppliers are increasing margins. Could you elaborate this a little bit on the cost risk for the PDO project, please? First of all, I'm actually quite happy that the suppliers are now reporting increased earnings because that means that they, as long as they earn money and are staying in positive numbers, it's actually positive because it means that they can invest in their own companies, they invest in more quality, et cetera, et cetera. I'm actually cheering for that. The numbers that are now being reported from Aker and others are baked into our existing CapEx numbers. I would say the market is progressing pretty much as we planned. The latest POs has actually been set at somewhat lower prices than we assumed back in December. Okay. Thank you. I'll let other analysts come with some questions as well. Thank you very much. Thank you, John. All right, the next question comes from Johan Charenton. After him, we have Teodor Sveen -Nilsen. Johan, please go ahead. Good morning, team. Hopefully, you can hear me well. I have three questions. Absolutely. Good morning, Johan. Thank you. Good morning, Karl. Just thinking about production, if you don't mind, can you please discuss water production levels at Edvard Grieg as we speak? Has Edvard Grieg production already fallen off plateau? If not, when do you expect this to happen? Second question will be for David on cash payments. You told us that there are no fixed for the second half of the year. Is that possible to know whether there is any, let's say, NOK-USD exposure edge as we speak? Potentially, is that possible to know about the payment dates for this cash installments? The last question is about basically variable remuneration for management. Can you confirm that production and production costs are among key performance indicators used to calculate this variable remuneration? If so, can you please provide more color on the weighting of this metric, so production and production cost, against performance indicators related to shareholder return? Thank you. Okay, excellent. Good question. Let's start with Edvard Grieg. I'm not going to comment directly on how the water production is behaving at the moment, because we're continually optimizing the total processing capacity across the Ivar Aasen and Edvard Grieg field, and of course, also the sub-tie-ins. When it comes to plateau, the Edvard Grieg reservoir in itself went off plateau earlier this year. That's largely been offset by the drilling of IOR wells into the same reservoir, and also acceleration of Solveig rates, which is tieback, which had been held back due to processing capacity at Edvard Grieg. We've done 2 out of 3 IOR wells with really good results, and we're almost back to full utilization of process capacity as we speak. Of course, no reservoir is infinite, so at some point in time, we expect this to trend onwards as well. Right now, I think we have really good control. 3D seismic is working, or 4D seismic is working excellently, and the first, two wells have actually produced, above-expected results. David. I can do the cash tax payments. How we typically do this is when we realize revenues, we also do hedging on the NOK-denominated amounts on a running basis to avoid having a FX exposure on the tax payments. With regards to payments dates for the installments, this follows a normal process, and you know the number of installments in the third and the fourth quarter. With regards to exact dates, I think I'll skip that one also due to commercial reasons. Fair enough. Do you want me to take the remuneration as well? No, I can do that. The variable remuneration, or the bonus schema for the management is actually the same as the for the entire company. We're running 1 bonus schema for the entire company. It basically consists of 3 components. The first one is a set of KPIs, of which production cost, CapEx, shareholder return is a part of the KPIs. That's weighted by approximately a third. We have execution of the project portfolio as the second component, weighted by approximately a third. We have a set of strategic objectives that are weighted approximately a third. Of course, quite a few of these, including a few of the production, KPIs, some of the strategic initiatives, but also the direct measurements of production and production costs are impacting the variable pay not only for the management, but indeed for the entire company. I can just add to that also for people who want to deep dive into this, we have a pretty extensive remuneration report also published on our web pages with all this information available. Thanks a lot. Have a nice day, and nice summer. Thank you. Thank you. Likewise. Yes, Teodor is next. After Teodor, we have James Hosie from Barclays. Teodor, go ahead. Thank you. Good morning, congrats on strong performance in second quarter. First question is on Sverdrup. Obviously, strong performance on Sverdrup these days. I just wonder, could we briefly discuss the potential for debottlenecking and increasing production further from the current level? Second question is on the current discovery. Definitely exciting discovery in the Norwegian Sea. I'm fully aware that you are not the operator, and you have a small share there. Is it possible to speculate a little bit around potential development solution? Is likely that Kvitebjørn will be a host platform or will it be any other host platforms? My final question there is on your updated guidance for production cost per barrel. I definitely understand that is partially driven by higher production guidance, but also driven by weak NOK and also some efficiency gains. Is it possible to quantify the split between the weak NOK efficiency and high production? That would be useful. Thanks. Yeah, excellent, Teodor. When it comes to Johan Sverdrup, as you know, we are currently running at about 755, which is the I would say, the tested capacity. Right now, I don't think the market should expect additional debottlenecking activities at this stage. The primary focus now is to sustain production and keep on drilling tieback wells. I think that it's a fair assumption to assume that we'll keep the current production potential as it now sits. When it comes to Carmen, I think I'll refrain from discussing specific tieback options. I think it's worthwhile noticing that there seems to be quite considerable exploration success on the Norwegian Continental Shelf. Not unexpected, I would say, from an Aker BP perspective. I think I've been on these stages for many quarters now, talking about our belief in the Norwegian Continental Shelf and how we continue to, yeah, initiate and run a quite active exploration program. It's actually quite encouraging to see that the discoveries like Lupa, now Øst Frigg, and finally, Carmen, is finally coming to fruition. It, it reinforces at least our belief in the Norwegian Continental Shelf as still a prolific exploration basin. On production cost, David- Yeah. Do you want to shed some more light? I can definitely do that. I alluded a bit to it also in my presentation. I think one way of looking at it is that underlying production costs is quite stable and in alignment with expectations. Then we have slightly less well maintenance activity, in particular, in the second quarter. That's also linked, of course, to the strong production efficiency in the quarter. When it comes to the Norwegian kroner, as you referred to, weak, but also we have seen lower power prices than what we originally expected going into the year. There's a mix of elements going into it, but I think that the biggest drivers are the power prices and the weak Norwegian kroner. Okay. Okay, thanks. Just a follow-up on the on your exploration comments, Karl. Are there any reasons for that hit ratio, commercial hit ratio for NCS should increase over the next few years? Do you have any views on that? We actually do expect. I think also in the last quarter, I said that this was going to be a very interesting exploration year, both for Aker BP and also for the Norwegian Continental Shelf as a total. Right now, I would say the same comment there actually applies also for 2024. We see on average, chances of success, so costs on these going up, we see volumes going up. What's basically happening is that new technology, new techniques, both in seismic processings, imaging, we're now seeing the emergence of what you would call a digitally emphasis exploration model, which is where we use machine learning, AI, et cetera, to extract data that's otherwise been difficult to extract from humans. There are a lot of these, I would say, underlying factors that seem to be coming together, and increase the chances of success on the Norwegian Continental Shelf. At least from an Aker BP perspective, we're really optimistic when it comes to the Norwegian Continental Shelf, particularly on, say, the scale below, let's say, 250 million barrels, which is basically tiebacks. That's also, of course, the reason that we're using 80% of our exploration budget on tiebacks. Okay, exciting. That's all from me. Thanks, and have a great summer. Excellent. Thank you. Yes. We have James Hosie next, and after him, it's Victoria McCulloch. Please, James, go ahead. Yeah. Hi, good morning. Thank you. I was just wondering if you could say anything on realizations at Johan Sverdrup. I mean, I've seen reports that recent cargoes have been getting a healthy premium to Brent, that compares to a discount a few months ago. Just how persistent do you feel that premium could be for the remainder of the year, if not further? Yeah, you wanna do that, Kjetil? Yeah, I can definitely do that. We also talked a bit about this in our last quarterly presentation, saying that differentials on Sverdrup had improved towards the latter part of Q1, and we've also seen that strengthening into the second quarter as well. If you go into, you know, Bloomberg and look at that data, you can see that Sverdrup is slightly in the positive, which is an improvement compared to what we saw in the start of the first quarter. That's positive. Of course, there are many different things that influence the differentials over time, so we don't speculate how that will trend going forward. We see strong demand for Sverdrup crude as we speak. Okay. There's been not any significant change in the last couple of months in terms of drivers for what's causing that premium? No, not specifically. No, not specifically. Okay. Thank you. Yes. Victoria is next, and after Victoria, we have Sasikanth Chilukuru from Morgan Stanley. Victoria, the floor is yours. Morning. Morning, thanks, all. A couple of questions for me. Alvheim efficiency seemed particularly high this quarter. Is there anything to underpin that, and how do you expect to see the production going forward for the remainder of the year? Also, could we get some color on where the maintenance is scheduled for Q3 for a reminder? I don't think I got the first part of your question, but were you asking about production efficiency? On Alvheim specifically, yes. Yeah. Yeah. Alvheim specifically. Thanks. Actually quite a few of our assets. I mean, we are reporting 96% average, including Ula and Valhall. Quite a few of our assets is actually really up there in 98%-99% production efficiency in the quarter, which is actually quite stellar results. That means that we haven't had any planned or unplanned shut-ins on these installations. I think the two stars in our portfolio right this quarter is actually Alvheim and Skarv, with close to 100%. Of course, you can't run an offshore installation with 100% production efficiency. There needs to be some maintenance, much of this maintenance this year is scheduled for September and August towards the back end of the year. That allows us to stay within the, say, summer weather window, but also avoid July, which is a little bit of a complicated month to operate in Norway. We expect that in Q3, we'll have significantly more, but planned shut-ins. The other thing that's worth noting is that the production efficiency is kind of a lagging KPI. We have a tendency of looking at the leading KPIs, the number of backorder, maintenance hours, et cetera, et cetera. All of those KPIs have been trending consistently downwards the last, I would say, couple of years. Since last summer and up to now, we've seen the benefit of, I would say, increased operational discipline, less maintenance backlog, more proactive maintenance, which also allows us to keep the background production efficiency quite high and avoid the unplanned shut-ins. That's the reason that you're seeing this trend. Of course, then in Q3, we will have to do planned turnarounds, which is basically planned inspections, but also inspections of inside of process modules, and there are some pipelines inspection, et cetera, et cetera. Thanks. That's very helpful. Just if I could ask one more. In terms of the timing on the exploration round slot that you're with APA, what is the rough timing in terms of expectations for that one? Right now, I would say, earliest, end of this month, latest, back end of next month. You don't fancy giving me a pre-drill estimate? No, I think I'll refrain from that because this is not really a proper exploration well, in a sense. This is the old Alida discovery. There's, we know that there's oil, so what we're actually looking for is producibility. Okay ... that means that there's quite a wide range in what you call data gathering programs when we get to the well. Okay. Thanks very much. Thank you, Victoria. Sasi from Morgan Stanley is next, followed by James Carmichael. Sasi, please go ahead. Hi, I was just wondering if you could hear me. Yeah, absolutely. Thank you, Sasi. Yeah, lovely. Hi, no, most of my questions have been answered, but I had a couple related to your production guidance. For 2023, you've still left a wide range on this upgraded production guidance. I was just wondering if it was possible to highlight the scenarios of where you see reaching the bottom end or the top end of that range. You did highlight high maintenance activity in 3Q, but was that reflected in your top-end guidance as or range as well? Just related to that, I was just wondering if there was any planned maintenance activity at Johan Sverdrup field specifically in the second half of this year. Thanks. The way to, I think probably the way to look at it is like a P90, P10 number. Then, of course, in the P90 number, when you do the statistic assimilation, there are certain breakdowns and certain events that we are, yeah, not necessarily planning for, but that we need to take into consideration when we're doing that kind of guidance. You will, of course, have noticed that we'll exit the Q2 significantly above the top end of our guidance. That means that if we do continue the way we have done, and I sincerely hope so, I can assure you that everybody in Aker BP is working really hard. Then, we assume that production will continue in that kind of manner, and will be impacted by the planned maintenance that we've already baked in. That planned maintenance haven't really changed from the original guidance we gave. The actual increase in guidance reflect the actual increase in performance throughout the year, and then we'll come back in Q3 once we've done that maintenance and see how that actually impacted the production performance so far. When it comes to Johan Sverdrup, there are a couple of smaller shut-ins planned, but we are still discussing whether or not to execute those in this year or move them to next year. That will depend on the expansion program that is currently ongoing. Nothing significant. Great. Thanks a lot. All right. James Carmichael is next. James, go ahead. Hello. Hi, morning, guys. Just a couple of sort of quick last ones from me. Just on Sverdrup again, I guess, you know, great to see the performance that you've achieved to date with increasing the capacity there. Just wondering if you've got a sense or if you've provided sort of guidance on how long you expect that plateau to last at that field? Then we see the sort of technical goodwill running through the P&L again on the impairment line. I was just wondering if there's some sort of rule of thumb that we can use to maybe model that going forward, or if there are just sort of too many moving parts within that calculation. Thanks. Yeah. When it comes to Johan Sverdrup performance, I completely agree. I'm deeply impressed by the job the operator is doing to keep Johan Sverdrup where they are. That, I think that's worthy of all the praise they're getting. When it comes to plateau rate, I don't think I'll comment too specifically on that and to refer that question to the operator, because it will depend on the activity program, the number of wells to be drilled, et cetera, et cetera. Then on impairment, David? I can take that. Yeah, you're spot on. Technical goodwill will be written down over the lifetime of the production of the field. You don't depreciate technical goodwill. Yes, we will be impairing technical goodwill. You know, everything equal on a quarterly basis, but then there are many moving parts, right? Of course, in particular, when forward prices move, then you get impairments on technical goodwill, which is typically higher than what they would have been if you were just depreciating over the production of the fields. Just to remind everybody, this is, of course, then linked to us including acquisitions at fair value in the accounts, and you have to allocate technical goodwill onto the different assets. Okay. There's no sort of rule of thumb, per barrel metric that we should be thinking about or anything like that? It's, it's difficult to give that estimate, given that there are so many moving pieces when it comes to how prices move. I think one way of guesstimating it would, of course, be to try and just take the technical goodwill that's allocated and then depreciate it over the production. I think that would be a difficult way of... You know, to hit on a quarterly basis, it will be difficult anyway. On a sort of a general rule of thumb over time, you know, in the end, when the production is ceased on the assets, technical goodwill will be zero. It'll be right toward the end of the field. Yeah. You'll know in 2040. Okay. Okay. Look forward to it. Thanks, guys. Thank you. All right. There seems to be no further questions. I guess that means we can close the presentation. Excellent. In that case, I would like to say thank you so much for attending this second quarter presentation from Aker BP. We do wish you all a very, very nice summer.