Aker BP ASA (AKRBP) Earnings Call Transcript & Summary

Good morning, and welcome to Aker BP's presentation of our Q2 2025 results. Today's agenda reflects a strong quarter with clear momentum across both our operations and our strategic priorities. We will begin with an update on our operational performance, which continues to deliver solid results. Then we'll move on to our field development portfolio, where we remain firmly on track and where we have sanctioned 2 new expansion projects this quarter at Johan Sverdrup and Yggdrasil . We are also pleased to share encouraging news from Yggdrasil on the exploration side, where we have discovered more oil in an ongoing exploration well. And as always, our CFO, David Tonne, will guide you through the financials later in the presentation. In the second quarter, production averaged 415,000 barrels per day, down 26,000 barrels from the first quarter. This decline was primarily due to a 1-month planned maintenance shutdown at Valhall and Ula. Despite the shutdown, we maintained a portfolio-wide production efficiency of 95%. Our other assets, including Johan Sverdrup, continued to perform really well with a production efficiency ranging from 96% to nearly 100%. During the Valhall shutdown, we also reached a key milestone on PWP-Fenris. The successful installation of the jacket and the connecting bridge for the new platform. Looking ahead, we expect lower production in the second half, driven by scheduled maintenance and natural decline. However, with a solid first half now behind us, forecast uncertainty has been reduced. As a result, we are narrowing our full year production guidance, raising the lower end of the range from 390,000 to 400,000 barrels per day. Unit cost edged up to $7.3 per barrel in the quarter, primarily due to lower production volumes, higher maintenance and a weaker U.S. dollar against the Norwegian kroner. Nevertheless, we remain firmly on track to meet our full year production guidance of $7 per barrel, a level that remains highly competitive within the industry. On CO2 emissions, the picture remained consistent. Our emissions intensity held steady at 2.8 kilograms per barrel, an industry-leading level that continues to set the benchmark globally. At the start of the year, we outlined our ambition to sustain production above 500,000 barrels per day beyond 2030 and to pursue further growth. We are working every day to make this a reality. On this illustration, the dark blue area represents our current business plan, covering production from existing fields, ongoing field developments and regular IOR activities. Key growth drivers include the large-scale Yggdrasil development, the Valhall PWP-Fenris project and a series of tieback projects to Valhall, Skarv and Grieg Aasen. It also includes the Johan Sverdrup Phase 3 project and the tieback of the East Frigg discovery to Yggdrasil, which have now both been formally sanctioned in the partnerships. This visible outlook support our target to produce around 525,000 barrels per day in 2028. Beyond 2028, the light blue edges illustrate our potential to sustain production above 500,000 barrels per day through infill drilling and tiebacks from known discovery across our portfolio. Progress this year has further strengthened our confidence in this trajectory. Looking even further ahead, we see additional growth potential beyond the current outlook. With continued exploration success and selective M&A, we see a clear path to expanding our production base well into the next decade. This is our ambition, and we are well equipped to deliver it. We have the people, the assets, the supplier, the digital ecosystem, the capital and maybe most importantly, the track record to make it happen. Our projects continue to advance steadily with several key milestones being achieved in the recent months. These include the successful offshore installation of the Valhall PWP jacket, the completion of the Fenris drilling campaign and others. And as we speak, we are preparing to install a jacket for the main Yggdrasil platform, the Hugin A. These achievements reflect the scale, pace and precision of our execution. They are the result of close collaboration across teams and partners, and they mark critical steps towards delivering on our long-term value creation plan. And since images speak louder than words, let's just have a look. [Presentation]

This video highlights the scale and complexity of the projects we are delivering and the impressive effort from our teams and alliance partners to make it happen. Offshore projects progress through distinct phases: engineering, procurement, construction, offshore installation, commissioning and finally, handover to operations. The successful execution is defined not just with progress within each phase, but by the ability to transition smoothly between them. If a project is off track, it typically becomes visible at these transition points. We are now roughly midway through the execution phase with engineering and procurement largely complete. We are well into the construction phase, and we reached a point where the modules are being assembled into complete platform units. This gives us a clear operational visibility into the remaining work and resource needs in the different projects. In this context, we have conducted our most comprehensive project review and budget update since sanction. The conclusion is reassuring. The plan holds firm. The projects remain on schedule for a planned start-up in 2026 and 2027 as originally communicated. That said, we have naturally faced some challenges along the way. Some work packages have experienced delays. Macroeconomic conditions have impacted prices and currencies and labor markets have tightened. And finally, the security situation in the Middle East have led to longer sailing distances between Asia and Europe. All these external factors are driving up costs across the industry. While we can't control global inflation, we can and do respond decisively. We have mobilized the necessary resources to navigate and mitigate these challenges, maintain focus and ensure momentum in the project execution. Now taking all of these factors into account, we now project a roughly 6% increase in investments for the ongoing projects. This includes a 10% contingency of the remaining capital, and the adjustment reflects the full scope of what is needed to deliver on time and with quality. Now importantly, when we look at the value creation plan from 2023 to 2028, the total investment estimate for all the PDO projects sanctioned in 2022 is up by only 3% to 4% on a like-for-like basis. This signal a strong -- is a strong signal of disciplined execution in a highly dynamic environment. Let's now turn to exploration and to what is arguably one of the most exciting wells on the Norwegian continental shelf this year, Omega Alfa in the Yggdrasil area. This well is remarkable, not only because we have discovered oil, which I will return to, but because we are breaking new ground in how we explore. Omega Alfa is pushing the frontiers of what is technically possible using advanced geosteering to drill ultra-long, high-precision horizontal sections with unprecedented speeds. This enables us to map the subsurface with high accuracy and pinpoint oil accumulations with confidence. Two years ago, with the d East Frigg well, we set a new benchmark by achieving more than 13 kilometers of reservoir exposure. Since then, we have equipped our rigs with wired pipe technology, a high bandwidth data link between the drill bit and the surface. This innovation allows us to drill faster, stay with greater precision and access significantly more reservoir in real time. To put it into perspective, a typical exploration well might intersect a few hundred meters of reservoir. Omega Alfa by contrast is on track to exceed 20 kilometers of reservoir exposure at only twice the cost of a conventional well. Moreover, the quality and quantity of the data we are acquiring are vastly superior, substantially reducing uncertainty and accelerating the time line from discovery to development. The East Frigg well is a prime example with only 2 years between the discovery and the final investment decision. Omega Alfa is a multilateral well targeting 5 different structures: Omega, Alfa, Alfa South, Sigma North East and Pi. The combined predrill volume estimates ranged from 40 million to 135 million barrels. Drilling started in May and is progressing really well. We have already covered the Alfa structure and parts of the Omega structure, confirming commercial oil volumes in the range of 20 million to 40 million barrels. Operations are now progressing towards the northern part of Omega as well as the Sigma North East and Pi, which together have a predrill volume estimates of 30 million to 70 million barrels. Geologically, this setting resembles the East Frigg discovery with thin oil zones sealed beneath a shale layer that effectively traps the hydrocarbons. We will, of course, provide further details once drilling is complete and the data has been more thoroughly analyzed. However, in my view, this is already a success and will contribute valuable additional volumes to the Yggdrasil development. In essence, we are also pioneering a new exploration method, one that paves the way for efficient future exploration in the Frigg area, west of Yggdrasil. Frigg was, as many remember, originally developed as a gas field in the 1970s and was decommissioned 20 years ago after producing 700 million barrels of oil equivalent exclusively of gas. The initial exploration well also identified an oil zone with an estimated in-place volume of 1 billion barrels of oil. However, this was never produced, as horizontal drilling was still years away at that time. Based on the current geological insight, we see significant potential for further oil discoveries in the Frigg area. And this represents a substantial upside for the Yggdrasil development. And that is why we, together with the Yggdrasil partners, have secured this acreage and will be drilling additional exploration wells in the years ahead.

Good morning. Aker BP has delivered another quarter of strong operational performance. And although commodity prices were down and we had planned maintenance at several fields, the operating cash flow was in line with recent quarters where we paid 2 tax installments. Our current investment level is high, reflecting strong progress on our field development projects that were sanctioned back in December 2022. As Karl has just mentioned, a thorough project review completed this quarter confirms that the ongoing projects are on schedule, while total investment estimates are up around 6% compared to original guidance. In sum, this implies a significant derisking of the business cases of these highly profitable projects. Furthermore, we continue to see substantial upsides as exemplified with the ongoing exploration in the Yggdrasil area. At the end of the quarter, Aker BP's financial position remains strong with ample available liquidity, low leverage and low net debt. Altogether, the quarter marks one more step forward on our value creation plan. We are well positioned to navigate market volatility, as we focus on maximizing shareholder returns by maintaining financial flexibility, investing in profitable growth and delivering a resilient dividend that grows in line with value creation. Let's now take a closer look at the main drivers behind the results. Net production declined slightly, impacted by a 1-month planned shutdown at Valhall and Ula for maintenance and project activities. Production in the quarter was 415,000 barrels of oil equivalents per day. And with a very small underlift, sold volumes ended at 414,000. Operating costs increased to $7.3 per barrel, driven by reduced volumes and a strengthening of the Norwegian kroner. Year-to-date, our unit cost is $6.9, and we are on track to deliver on our full year guidance of approximately $7 per barrel. Cash flow from operations reached $1.2 billion in the quarter. This is in line with previous quarters where we have paid 2 tax installments, as can be seen on the illustration down to the left for the second and the fourth quarters last year. Investments in the quarter increased to $1.9 billion, reflecting high activity across our project portfolio. Within financing cash flow, the main item was the dividend payment of $0.63 per share. Zooming in on a few items in the income statement. With lower volumes and realized prices versus the first quarter, revenues decreased to $2.6 billion in the second quarter. As mentioned, production cost per barrel increased due to lower volume and stronger NOK, but remained relatively flat on an absolute level. Net financial items were impacted by currency losses on non-dollar-denominated balance sheet items, mainly from the revaluation of our euro-denominated bonds, while our Norwegian kroner hedging program covering current tax liabilities and investment plans generated a solid gain this quarter. As shown in the notes to the balance sheet, our derivatives positions are now valued at around $200 million. Impairments totaled $717 million in the second quarter, consisting of technical goodwill on Johan Sverdrup, Valhall, Grieg Aasen and Alvheim, mainly driven by lower forward prices for oil and gas. Since goodwill impairment has no tax impact, this leads to an artificially high reported tax rate of 138%. Adjusted for impairments, earnings per share was $0.62 in the quarter and the effective tax rate was 75%, which should be more in line with expectations. For more information on technical goodwill and impairments, I recommend watching the explanatory video that our IR team has published on our website. Let me also briefly comment on cash flows. Taxes paid was relatively high and was, as mentioned, impacted by 2 installments this quarter compared to 1 in the first quarter. These payments are for taxes accrued in 2024. Taxes accrued in the second quarter was significantly lower than the taxes paid, which materially reduces tax payables in the balance sheet. For the quarter in isolation, this lowers free cash flow, but as taxes payable is reduced, we also expect lower tax payments in the coming quarters. The observant reader may also have noticed a new line in this statement, investment in financial assets of $300 million. This is short-term financial placements in liquid notes to enhance returns on surplus cash, while maintaining liquidity. While this is formerly classified as an investment, it is considered as cash equivalents under our bank facilities and by rating agencies and is also included in the net debt and leverage ratio calculations. With the strong operational performance flowing through to the financial performance, we exit the second quarter with a continued strong financial position. Net interest-bearing debt increased to $4.6 billion, but as we illustrate to the left, the main driver was the high tax payment in the second quarter, which reduced tax payables with an almost equal amount. Our leverage ratio remains at a low level, now marginally up to 0.4x net debt to EBITDAX. Total available liquidity remains conservative at $6 billion, providing a lot of flexibility. The decrease quarter-on-quarter is driven by the tax payments and a planned step down in our undrawn RCF facility from $3.4 billion to $3 billion. Following the completion of our comprehensive project review this quarter, we have also updated our total investment plan for 2025 to 2028. The approximate 6% increase in investments for our ongoing field development projects is now reflected in this updated plan. We continue to expect 2025 to be the peak investment year with capital expenditures reaching approximately $6.5 billion before tapering off from 2026 and onwards. In aggregate, the updated net estimates for the ongoing PDO projects reflect an upward revision of around $1.2 billion. As all of these projects fall under the 2020 tax system with approximate 87% tax deduction, the after-tax effect of this increase is between $150 million and $200 million. One additional thing to note is that although this investment profile is sensitive to future changes in foreign exchange rate, the actual financial exposure to a further strengthening of the Norwegian kroner is limited, as we have over 75% of the planned NOK expenditures for the next 3 years hedged at an average dollar-NOK rate between 10.5 and 11. The updated investment estimates have a marginal impact on project economics, our value creation plan and the financial metrics for the period up to 2028 that we presented back in February. The impact on estimated cumulative free cash flow generated across oil price scenarios largely follows the after-tax effect of the increased CapEx with some variations due to phasing of tax and financing costs. Consequently, our financial metrics remain very robust across most possible oil price scenarios. Assuming a continued 5% annual increase in dividends, our leverage remains comfortably below the internal threshold of 1.5x and well within the bank covenant limit of 3.5x. And even in a prolonged $50 oil price environment, where we have conservatively assumed $50 per barrel from the beginning of 2025, as we also did back in February, our modeling indicates that leverage only temporarily exceeds 1.5x in 2026 before declining again in 2027. In summary, our value creation plan is on track, and we have the capacity and resilience for attractive shareholder distributions in the years to come. Now on the topic of shareholder distributions, our guiding principle is to maintain a resilient dividend that reflects our financial strength and outlook. And to be clear, our ambition to grow the dividend by at least 5% annually through this investment cycle remains firm. For 2025, our plan is to distribute a total dividend of $2.52 per share. We have already paid 2 of the 4 quarterly installments and the Board of Directors has resolved to distribute the third installment of $0.63 in the third quarter. Now let me round off with a few comments to the main elements of our 2025 guidance, starting with near-term tax payments. As mentioned, the tax payments in the second quarter were relatively high at around $1.5 billion, and is the result of taxes accrued last year. Now in the third quarter, we will start paying taxes related to 2025, which will be significantly lower, as a high investment level this year leads to higher tax deductions. This is a key feature of the Norwegian tax system. It provides resilience to market volatility when investing in profitable growth. Moving on to the key operational parameters. Production averaged 428,000 barrels of oil equivalent per day in the first half of the year, above the top end of our full year guidance range, but in line with our expectations. We still anticipate some natural decline as the year progresses along with planned maintenance shutdowns in the third quarter. But with half of the year now behind us, we lift the low end of the guidance range and update the full year estimate to 400,000 to 420,000 barrels per day. Production cost is $6.9 per barrel year-to-date. And although the recent strengthening of the Norwegian kroner adds some risk to the full year estimate before accounting for the financial effects of our hedging program, we maintain strong cost control and still expect to end at roughly $7 per barrel for the full year. Investment activities are currently at peak levels with construction activity at full speed and drilling campaigns ramping up. We invested $3.1 billion in the first half of the year, and we lift our full year guidance to approximately $6.5 billion. The increase in 2025 is a combination of very good progress across the projects, updated investment estimates and the cost impact of the strengthening of the Norwegian kroner. While most of the after-tax financial impact of the latter is hedged, the reported investment levels on a pretax basis is still impacted. Exploration is progressing in line with plan. The program is somewhat front-loaded in 2025. So we still expect exploration spend of around $450 million pretax for the full year. Abandonment activities are also on track, but we lowered the cost estimate to around $100 million, reflecting good execution, but also some phasing of plugging and abandonment activities to 2028. And with that, I leave the word back to Karl for some concluding remarks.

Thank you, David. So to sum up, we have delivered a solid second quarter operationally, financially and strategically. Our projects are progressing well. Our exploration efforts are breaking new ground, and we remain firmly on track to deliver on our long-term ambitions. We continue to navigate a complex external environment with discipline and resilience, and we're confident in the strength of our portfolio, our people and our partnerships. We will now take a short pause before opening the Q&A session. To participate, please use the Teams link provided on the web page or if you prefer to listen only, please stay tuned, and we will resume in 1 minute. [Break]

Welcome back, everybody. And as usual, Kjetil Bakken, our eminent Head of IR, is running the queue of the questions today. And Kjetil, I assume we have a first question here or first caller.

We certainly do, Karl. And the first question is from Matt Smith from Bank of America. Please go ahead, Matt.

A couple, please. The first one would be touching on the capital increases for the ongoing projects. I just wondered if you could give us some sort of sense in terms of the contract structures and really trying to sort of reconcile what proportion of the project costs still are exposed to price inflation or price variation from here. And that would also give us a sort of a sense of what the current rate of inflation today actually is, if we have an appreciation for what costs were already locked. And then the second question would be moving on to Johan Sverdrup and Phase 3 with that project now FID-ed expecting production in 2027. And just to give us a bit of a broader understanding of what you expect in terms of performance and contribution from that phase by the time that project starts to contribute?

Excellent. Thank you, Matt. Well, I'll start with the CapEx question. All these projects, they go through different phases, right? So you start with feasibility, then you move into early phase engineering and then you have detailed engineering and ultimately, you get into procurement, prefabrication and then construction and assembly and then finally commissioning and then towards the end, hand over to operations. And as these projects progress, you get better and better clarity of both scope, volume, prices, et cetera. So you have some sort of estimation going in and then you have some sort of realization, as you transit from one phase to another. So what's happened now is that we have gone from basically we're done with engineering, we're basically done with procurement, we've done most of the prefabrication. There are only 3 preassembled units yet to be delivered until we're done -- completely done with also the prefabrication. So now we're moving into construction. So what we've done is basically a new bottom-up revision where we've taken everything that's behind us, which is basically the earlier phases and then had a new look at what we had to do. And obviously, as we are on time, there's not a lot of movement in terms of timing cost. So what you've basically see that there is some price increase outside of what we expected it to be. There is some movement because of things we cannot control. For example, the security situation in the Middle East has increased the sailing routes from Asia to Norway by about 4 to 6 weeks, which means that we had to find work or actually accelerate work to compensate for that time. There has been some FX movements outside what we've had, et cetera. So it's a lot of smaller things actually leading up to this change. Now basically, I would say the price -- there's very, very little scope variation. So there's almost no scope change inside the structure. This is quite different from what you normally see where scope variations are the main driving change in terms of CapEx. So this is basically us just updating the estimates that we had going into the main construction phase. This also means that what is ahead of us now is basically assembly, commissioning and then hand over to operations, which is far easier for us to control, as it's essentially hours as an input factor because both engineering and procurement is essentially behind us. So we felt it was prudent to update the market on where we were in CapEx at this point in time. Now the good news is that the plan still holds, right? So with all these variations, with all these changes we've seen in the market since we sanctioned it back in 2022, maybe I'm pushing the point here, but I still believe that if you look at the totality of that value creation plan and a price variation in the range of 3% to 4%, that's actually pretty good performance when you look across the quite fundamental changes. We've seen both in capital markets, but also in retail markets in those 3 or 4 years or 5 years since we sanctioned the project. Now moving on to Johan Sverdrup, Phase 3. Do you want to do that?

Yes, I can definitely do that. So as you mentioned, we have sanctioned Phase 3 this quarter, 2 subsea templates. Initial scope is 8 new wells. And then there is an additional 4 available well slots that could be leveraged for additional IOR drilling. Start-up time 2027. This will, of course, not only add the additional resources of roughly 40 million to 50 million barrels gross terms, but it will also -- of course, also accelerate production. So that's a part of the business case of sanctioning Phase 3. In terms of the exact contribution on production, I think I'll refrain from trying to give a detailed estimate of that. That, of course, is linked to the optimization of the full field. But of course, this is included in our production profile up until 2028. And we're very happy to have this milestone behind us now and moving into execution. Yes, I'll stop there.

Yes. Next question comes from Christian Bi of Citi.

I've got 2, please. The first one is on hedging. We've seen your U.S. peers across the Atlantic hedge quite aggressively this quarter, take advantage of the more premium to lock in high oil prices through 2026. So it's a bit surprising to see that your hedge position hasn't changed materially and only limited to just 2025, especially given your policy allows hedging up to 100% of your production over the next 12 months and 75% for the subsequent 6 months, if I remember correctly. Could you please share your thinking here? Have you considered increasing your hedging to support cash flow through the production trough in 2026? The second question is on exploration. I'm sure there will be plenty of questions on Omega Alfa, but I'd like to shift your focus to frontier exploration first. With both Bounty and now Rondeslottet returning dry results in the first half and both having been positioned as high potential opportunities, should we expect a reset of expectations around your frontier exploration strategy? Specifically, are you looking more towards near field or lower-risk prospects? And given potentially lower complexity, are you also considering how much to spend on exploration going forward? I'll leave it there.

Excellent. Let's start with hedging, David.

Yes, I can do that. So you are correct. When you look at our current hedging positions, we have roughly 18% of the after-tax exposure hedged for the second half of this year using put options. And then we have policies in place that allows us to hedge further out in time using different instruments. I think when we look at hedging, we look at the totality of the business profile, but also the fiscal system that we are in. So comparing us against sort of U.S. peers is not necessarily the right way to think about it, given that we have a tax system, which makes it, call it, less relevant to some extent to protect liquidity to hedge. But that being said, we are constantly sort of evaluating our hedge positions, also given the recent volatility that we have seen. So this is something that we are consciously considering as we progress towards 2026.

Thank you, David. And then moving on to exploration. Let's start with the strategy part of your question first, Chris. So for quite a few years now, we've basically had this balanced view on exploration, where we spend roughly 80% of the expect budget on what you could call near-field exploration. And then near-field for us is anything that's 50 kilometers or less away from our own infrastructure. So it's a pretty big area. And then we spent 20% on frontier exploration. I don't really foresee that changing going forward. I still believe that we will spend the majority of our capital building up under the value creation plans inside our assets, and we'll spend 20% or so, of course, dependent on what kind of prospects we see. Now Bounty and Rondeslottet are 2 very, very different plays, right? So Bounty is a classical high-risk, high potential play opener type of prospect. And you will, of course, see the majority of these play openers fail. That's the nature of the game. The exploration potential here in terms of probability is probably around the 20% mark of discovering a barrel of oil, right? So there's a certain risk element associated with this activity. That's also reflected in our strategy. Now Rondeslottet is a very different animal. For us, that is the first dip of our toes into this high potential play of tight oil on the Norwegian continental shelf. As I said last quarter, I don't believe this is going to be a sprint. I believe this is going to be a marathon. And I do believe that there will be lots of these wells in the future before we crack that code. Rondeslottet also was a bit of a different one, right, because the first Rondeslottet well drilled by Ellida -- by Equinor called Ellida back in the day, discovered oil. Now we had this hypothesis that because of the depositional environment, you would see better porosity and permeability higher up in the structure. We don't know exactly what happened, but at that position, there was little or no reservoir. So there might be some erosion event that have happened in geological time between these 2 geological positions. So that's a very -- there are 2 very different cases. So no, there won't be a fundamental reset of our strategy based on those 2 wells.

Sorry, just one follow-up. Is there any intention to revisit Rondeslottet through further drilling?

First, I think we'll have to make up our minds about what actually happened here. So right now, I think that is -- that option is paused. There might be a comeback if the geological evaluation tells us that, that is an opportunity. But for the moment, we do not have any such plans, no.

All right. Then the next question comes from John Olaisen from ABG.

A little bit on the increased CapEx. You mentioned that you have a 10% contingency on the CapEx for new projects. I just wonder if you could specify, is this contingency for the increased CapEx? Or is there a 10% contingency for the whole budget for those projects?

Yes. So what we've done now is that we have done a new bottom-up estimate. So when I'm saying 10% contingency, it's a 10% contingency on top of the new estimate on the going forward expenditure, right? So there are some of these expenditure that's behind you. And then the estimates, as you correctly point out, gone up about 6%. And of those remaining CapEx in the future, 10% is contingency.

So 10% of what is left on the total projects from here is contingency?

Absolutely.

All right. Does that mean that you use the 10% contingency for the CapEx that you spend up until now?

No, a little less. So the total -- what we are about, I don't know, 45%, 50% into the total CapEx program. And some of the contingency that's behind us has been consumed, and some of this has been transferred into the future contingency amount.

But then a little bit on the Yggdrasil development. I like the video. It's always nice to see it actually how it works. But could you tell us a little bit more about which modules that are being constructed in Asia? It seems that all the projects going on in Norway seems to be going on track. But could you tell a little bit about the key risk you have towards Asian yards please?

Yes. So we have 2 primary Asian prefabrication yards, so what you call preassembled units yards. So NOV in Batam is producing MEG, TEG regeneration and sulfur reducing units. That's basically taking the sulfur out of the seawater before you're injecting it. And then Dubai dry docks is constructing more, call it, preassembled units, with basically steel works with piping and valves, which is used to stack up, as you saw in the video before we finalize the construction at Stord. Yes. I think that the activity in both these yards has actually been pretty good. It's not what we're used to in Norway, of course. But I would say that we've been able to sail away on time for all the pulse that's been -- preassembled units that's been delivered out of Dubai, and it looks good also in Malaysia. But the sailing time has increased, right? So we can't no longer go direct via the Sinai channel. We have to go around the Cape. That means that we have to spend some additional money both on sailing, but also on catching up those weeks that we lose in transit. And then you're absolutely right, we spend a little bit of resources monitoring and following up these yards to make sure that we have the quality we need when it gets to Norway. I think you're muted for some reason, at least we lost the sound.

Sorry, I think it was muted. When will all the key components being constructed in Asia? When will they have left the yards in Asia? What's the plan for that?

The last departure, I think, is one of the last weeks in October, everything will be en route to Norway.

All right. Great. Then my final question, with the increased CapEx and also taking into consideration the exploration success at Yggdrasil -- in the Yggdrasil area, what do you estimate to be the NPV breakeven for Yggdrasil as it stands for now, including exploration success, if that's the number you have?

Yes. I don't think we've done that. That's estimation. But I think last in Q2 -- in Q1, we talked about sub 25. And then it doesn't fundamentally -- because of the CapEx before tax doesn't fundamentally change the after tax. So it doesn't necessarily impact the breakeven that much. And then we have 1 quarter left. So I would probably say that we're still sub 25, maybe even sub 20.

And just to be clear, John, that's on a point-forward basis. So when we look at the full portfolio, including the adjusted CapEx estimates, we're still between $35 and $40 full life cycle breakeven on the project. And this does not include the latest discoveries in the Yggdrasil area. So we keep adding to the profitability of the project. So I think one additional point from my side here is that I think where we are now in the phasing of the project, this sort of updated baseline, including the milestones that are completed, marks sort of a significant derisking of the project. And of course, we keep adding to the profitability as we add additional resources.

I think one additional point when we construct the Yggdrasil, we always thought of this as a hub. So that means that the -- both the top side but also the subsea infrastructure is all prepared to do exactly what we've now done in the East Frigg and with now the Omega, this will be another bolt-on. We have standardized subsea equipment, standardized wellheads, standardized well technology, et cetera, et cetera. So this is basically add-on. So the additional CapEx will be limited. And that's, of course, increasing the NPV as we continued to add resources without, let's say, buying the infrastructure that you normally do in these tiebacks.

So when you say $35 to $40, that excludes both East Frigg and the other potential exploration success you might have?

That was the starting point.

And Omega and everything?

Absolutely. That was a starting point back in 2022, yes.

And what kind of NPV breakeven will you need for East Frigg and Omega and for future exploration success, do you think?

So we haven't really updated the estimate. So we are still using $35 as kind of a benchmark for these kind of decision basis. But obviously, both East Frigg and also Omega, when the time comes, will be significantly lower than that.

Okay. Then the next question comes from Nash Cui from Barclays.

I have 2, if that's okay. So the first one is just to get some clarification on CapEx, especially for next year, 2026. I wonder, given the increased level of activity this year, your ForEx change hedging, can you provide some color on where we will land on CapEx next year? Then my second question is more on leverage and working capital. Let me see -- I'm just looking at Slide 18 of your presentation because leverage ratio has reached 0.4 this quarter, kind of the highest level for the last 2 years. And this quarter, we also had a very positive working capital movement. I wonder where do you see leverage ratio by the end of the year? And how should we think about working capital evolution as well?

Yes. Let's take CapEx first, and let's start with 2025 then, right? I think in the last quarterly presentation, I said that I would be very happy if we reached the upper end of the CapEx estimates for 2025. And now we have obviously increased those quite a little bit. So that basically means that as we're taking delivery of quite a lot of these procurement items, we are also closing out those accounts. So in a way, you can say that the more we spend in 2026, the better it is because it actually proves that we have taken delivery of a lot of these procurement items and are now shipping them back to our site, as I went through both in my presentation and my answer to John. And then for 2026, I don't think we have guided specifically apart from what is in the deck. But the way I would think about this is that the majority of the CapEx in front of us is basically a result of construction activities, meaning that we've passed procurement, we've passed engineering. So you shouldn't expect that kind of increase in 2026 that you've seen in 2025 because that's basically catching up with price increases and other out-of-control effects. Leverage rate?

Yes. Let me just add one additional point to Karl's comment around the 2026 CapEx. Just to be clear for everybody, as I also said in my presentation, the updated investment profile that we now have in the slide deck includes also adjustments to the other years, not only 2025.

Yes. Which is Slide 19, for your reference.

And then when it comes to leverage ratio, Naisheng, it's the same. So we have a slide in the deck, which illustrates our leverage ratio development across various oil price scenarios. So -- and that's also been updated with the latest estimates on CapEx. So I'll refrain from giving a point estimate with regards to the leverage ratio because it obviously depends on commodity price and so on. But I think that will give a very good outlook for where we expect to end depending on ranges of outcomes in commodity prices.

Okay. Next question is from Victoria McCulloch from RBC.

So maybe first of all, on Yggdrasil, can you give us an idea of how much the East Frigg now that it's added to the development has been able to add to the plateau at Yggdrasil? Just to give us an idea of the impact that Omega Alfa could have if it characterized in the same sort of size and way as that development has? And secondly, could you give us an idea of some of the maintenance that's scheduled for Q3 that's helping, I guess, is driving your guidance for lower production in the second half of the year? And finally, it looks like you've given us quite a few wells into 2026 in as part of your -- the exploration schedule on Slide 11. Of that, it looks like there's fewer wells being drilled. Should we see that as just a preliminary estimate and the exploration sort of budget is broadly remaining flat into next year given the sort of opportunities that you're clearly unlocking in Yggdrasil as well as other geographies? Or is that a reflection of a slightly lower sort of schedule for next year as it stands at the moment?

Yes. Let's start with the last question. I think my -- it will be a fair assessment to say that the expect next year is broadly in line with what we delivered in 2025. The fact of the matter is that we are, at this point in time, rig constrained. That means that even if we wanted to drill more wells, we would have to take on additional rig capacity, which we obviously don't want to do simply because we are trying to make these rigs into performance machines. And every time you shift rigs and out of the portfolio, you get some sort of start-up issues that happens every single time. Moving on to Yggdrasil. One way to think about this is -- and it will, of course, depend on the phasing of these reservoirs because Yggdrasil consists now of 8 to 10 different reservoirs. There are 3 production systems at Hugin A in terms of oil, gas and water separation. So it will depend on the phasing of the different reservoirs, but an easy way to think about it is that roughly 50 million barrels should equate to approximately a year in extended plateau, if you were to very simply simplify the way to think about it, right? And if you remember correctly, that's about the size of East Frigg. And then depending on how much you find in the remaining part of Omega, this could now range from, let's call it, the midpoint between 20 and 40 is 30 and then you have 30 to 70 in the remaining part. So you could easily end up anywhere in the range of, let's call it, 60 to 100. Obviously, 100 would be quite a big development for this area. Now this is exciting enough, Victoria, but what's really making Omega exciting is that we have proven that we have an ability to explore oil without penetrating these oil zones. So that means that as we are moving next year into the Frigg main, we can actually now drill a trajectory into Frigg and control the top or the bottom and the reservoir and understand the saturation profile in that whole trajectory. This is -- it's actually groundbreaking in terms of exploring for these oil pockets. So that's what's really making this exciteful. This could be a significant upside for the Yggdrasil area.

And then maintenance in Q3?

And then maintenance in Q3. So the way to think about this is that there's a lot of smaller stuff like ESDs and/or emergency shutdown tests and different tests of safety equipment. The majority of the activity is related to about a month stop at the Grieg Aasen infrastructure. And then we have about 2 weeks at Alvheim, if memory serves me right. So I would -- very simply, I would basically look at the Q2 maintenance program as similar to the Q2 maintenance program in terms of production effect.

Super. And just to confirm, the production profile that you provided on Slide 7, that does already include East Frigg opportunity within...

Absolutely. As we said, this now includes East Frigg, it includes the Johan Sverdrup Phase 3, and it includes some of the IOR activities that is inside the base business plan.

The next caller is Chris Wheaton from Stifel.

Three questions, if I may. Firstly, strategically, I would think you're starting to think about what happens next after Yggdrasil in terms of project sanctions because if you're going to say -- if you want to get this production on in '28, '29 and maintain that plateau above 500,000 barrels a day, you need to be thinking about sanctioning them next year, I would think. I'm interested in your thoughts as to what's front of the queue for the next set of project sanctions being able to keep the conveyor belt, the manufacturing process and continuing to keep that going as production activity -- or sorry, development activity starts to ramp down the Yggdrasil over the next 18 to 24 months. My second question was on the Omega, East discovery, if you've really found a way of tapping into tight oil here, I'm interested in how much of '26 exploration campaign could be changed at this point to try and focus on that because it feels like that ought to be some of your lowest incremental cost to develop so your highest incremental return resources given the hub at Yggdrasil and therefore, you should be focusing on those. I'm interested in your sort of capital allocation thoughts there. And lastly, a question for David. Your result accounts is always extremely beautifully easy to read. The one number that left out at me was the $350 million of other working capital inflow that wasn't inventory or trade payables. And I wondered if you could explain what that was because I thought first, that was derivatives, given you talked about your hedging of currency and -- but that doesn't seem to show up in the balance sheet. So I wondered if you could explain what that $350 million was, please?

Thank you, Chris. Really good questions. So let me start with the strategy. I think you're absolutely right. We are already starting to think about what's post 2027. So maybe 2 avenues of how to think about that, the first one is basically the portfolio. So a lot of the stuff that will happen post 2027 will, to be honest, be, you could call it, tiebacks, a series of tiebacks or lifetime extension projects, et cetera, et cetera. So we are already kind of doing a lot of the prep work while we are executing. So in a way, there's a balance between keeping focus on the execution in this critical phase and then, of course, starting to think about the future. So what we've done from an organizational perspective is we have split those 2 organizations. So I have now one project organization who is only focusing on executing what we've already committed to and decided. And then we're setting down a new team, which is taking all the beautiful learnings and all the good things that we've done in this, call it, generation of execution and then turbocharging that into the next generation of execution. So next generation, that will be digital native. There won't be any documents. We are looking at a new generation of commercial models with the alliance partners, et cetera, et cetera, a long, long list of activities. Then quite a bit of this is flowing in either through the drill bit or through the existing portfolio or through possible M&As. And the way I would think about this is that in the future, post 2027, you won't necessarily see the big topside project that you've seen now with PWP and Yggdrasil. You will see much more of these tiebacks going at high speed, where the game is to get from discovery to production as in a short as possible time. So that's what we're basically focusing on going forward, if you want a bit of a broad stroke. Changes to 2026 program. The reality is that for 2026, maybe even for part of 2027, we will be constrained by rig activity. So even if we wanted to fundamentally change that program, we will be very disciplined because we know that any changes to these exercises comes with an execution risk and an execution cost. What we have demonstrated now with Omega is that we have an ability to fundamentally change the way exploration is done on the Norwegian Continental Shelf. We have drilled reservoir sections at unprecedented speeds that is outside the normal, you could call it, parameters of drilling. And we've proven that, that is safe, and we can actually steer and we can actually monitor the whole reservoir in one go in real time. So it's quite a fundamental change. Now while we are acquiring all these data, we also want to go back and have a look at what that actually means. What does it mean in terms of our drill-out strategy? What does it mean in terms of do we stop drilling exploration wells and go directly for keeper wells? So how do we actually think about this? So my view on this, Chris, is that as exciting as it is, it's worth taking a little bit of a breather and having a look at what we've actually done and how that will impact our strategy. So I don't foresee big changes for the 2026 program because, one, I'm very constrained. And two, I really want to think about how we can actually leverage that possibility to the maximum of its capability. Then you want to talk about financial and working capital.

Unless you want to go into the nitty-gritty of the notes?

You want to switch places?

No, no, no. So first of all, of course, thank you for the kind words with regards to how we position the accounts. So the $350 million that you're talking about, it can be split in 2 things, and you find more details also in the notes. So it's other short-term receivables and other current liabilities that change. And on short-term receivables, one of the key things that we see a positive impact from is a reduction in prepayments. So this is actually an effect of the progress on the projects. And then the other one actually with regards to current liabilities is also linked actually to the increase in investment level. So as we increase the spending, that typically also have a positive effect on working capital as we typically pay the bills slightly after the work has been executed. So -- but more information in Note 8 and 14.

Can I have just one follow-up, if I may, just -- Karl, just on your answer. Given the cost inflation we're seeing, are you -- back at the CMD, you talked about $15 a barrel for incremental project -- breakeven incremental projects. Are you still happy with that number despite the inflation you're seeing? Because it sounds like all the manufacturing process improvements you can put in place that you've just talked about, which you're clearly super excited about, that feels like that could offset some of that inflation. Are you still happy with that $15 number?

If you talk about CapEx per barrel, is that what you're talking about $15? Yes, I think I'm actually quite happy with that number. Some of these will be lower and some of these will be higher, but on an average, I think that will be a fair assessment. And then that being said, I think you're on to a point there that I don't think a lot of captured is that we have actually offset quite a lot of the price increase by a basic increase in productivity in preassembly and prefabrication. And a lot of these, call it, early phase investments, both in as an alliance but also into technologies like digital and machining and fiber lasers and all of that stuff, there's a long, long list, have basically ensured that we are able to catch up even as prices has increased and sailing times has increased and all the stuff we've been able to kind of safeguard the time of these projects. So if we hadn't made those investments, you would have seen different numbers.

No, that's very clear. No, I look at what you're doing in the North Sea and think it's amazing and I compare it to the U.K. and think it makes me want to cry. Thank you.

Next question comes from Mark Wilson from Jefferies.

Okay. Gents, just checking, you can hear me.

Yes, we can. Absolutely, Mark. Go ahead.

Very good. Okay. So all the questions are focused on Yggdrasil and the developments and yes, great job going on there. But I'd just like to switch and just ask some final questions on Johan Sverdrup. The first of which ties in a little bit to what you're just saying about development costs. Johan Sverdrup Phase 3, 40 million to 50 million barrels and $1.3 billion or -- NOK 13 billion or $1.3 billion. It's quite a high unit CapEx, I would calculate there about $29 a barrel. Maybe you could just speak to that in terms of the relative cost there to add 40 million to 50 million barrels at Johan Sverdrup. That's the first question. And the second would be whether you've started drilling those multilaterals yet? And if there's any update on your expectations of the plateau length at Johan Sverdrup?

Yes. Do you want to do the CapEx per barrel?

Yes, Yes.

I've been discussing this quite a lot. It's a good catch, Mark.

Yes, I agree, Mark. So if you just look at the CapEx per barrel number, I agree that's high. But remember that the investment in Phase 3 is also linked to acceleration. So that's an important part of the business case, which drives the profitability of the project. And then in addition, the initial phase of Phase 3 is drilling 8 out of the 12 well slots. So in addition, we also have room for more IOR and infill drilling out of those templates. So although the CapEx per barrel number is high, the profitability of the project is also very high. So this is one of the reasons why we need to look at a lot of different parameters when evaluating the profitability of our investment decisions.

So what you're basically doing, Mark, is that you're investing a little bit now because the investments, if you were to drill these last 4 wells at a later stage, would be significantly higher. That, of course, pushes the CapEx per barrel up beyond what you would normally see if you were just investing in the infrastructure necessary for the first 4 wells. And then as David said, a lot of this is also about exploration and not necessarily about net reserves.

So is it fair to say then there's additional contingent resources that could come from the additional wells, IOR or even multilaterals out of those same templates?

Yes, that's exactly why we're doing this. So we have a tendency in the oil and gas industry to kind of overpredict and not necessarily understand the kind of outcome space that you can have following these resources. And as we've talked about before, these kind of reservoirs, they have a tendency of getting bigger. We have the tendency of needing more wells to extract at the optimal rates, et cetera, et cetera. So that kind of experience from a philosophical perspective that's been baked into also Johan Sverdrup Phase 2. Yggdrasil is a bit the same, right? We've built almost twice the number of well slots that we will initially set into production. And now you see what's happening with East Frigg and now with Omega and the other exploration wells to come is that this is actually necessary and brings down the ultimate cost of the project in a life cycle perspective. Moving on to the MLTs. Yes, we've done the first one. It's just set into production. And I don't want to share too much details. I think the operator should do that, but I'm very happy. I think...

In which case, we'll leave it there.

Good that you are happy, Karl. The final question for today comes from James Carmichael from Berenberg. .

Just one quick one. Just a follow-up to one of your answers earlier. Karl, you mentioned that from 2027 onwards, the expectation shouldn't be around sort of major topside projects. It's going to be more sort of near field or ILX type activity. I'm just wondering if that -- or if there are any implications from that statement with regard to Wisting or if that is still sort of ongoing in the background?

Yes. I was referring to what we are operating in Aker BP and obviously, we are partners in Wisting. So there are, of course, projects on Norwegian Continental Shelf that will require large topside construction activities. Wisting is one of them. From an Aker BP perspective, our view is that quite a few of the projects going forward now will be either a lifetime extension type of project or they will be tiebacks or there will be a combination of these. You might also see quite a few of these, call it, copycats of unmanned production profiles -- or production platforms. We also see a little bit of a -- yes, quite a few actually potential for reusing that technology in the future, right? So I'm not going to disregard that there will be topside activities in the Norwegian yards, but quite a few of the projects in the Aker BP portfolio will be dominated by subsea tiebacks.

Then I'll have no further questions. So...

Then I think we say thank you so much from David and Kjetil and myself, and we wish you all a very, very good and safe summer.