Good morning, everyone. With this intro from the successful installation and startup of the Tyrving Field, we welcome you to Aker BP's third quarter in 2024. It will, as usual, be given by our CFO, David Tønne, and myself, followed by a Q&A session. The Tyrving Project received government approval in June last year, with an original plan to commence production in Q1 2025. However, through effective planning and execution together and alongside our alliance partners, we managed to start production in early September, five months ahead of schedule and below budget. This is a prime example of value creation here at Aker BP. During the quarter, our operational performance has been excellent, marked by high production efficiency and effective execution despite maintenance activities at several assets. We have consistently demonstrated strong cost discipline, and we maintain our position as a global industry leader in low emissions.
I am also pleased to report that our projects are progressing well. Fabrication, installation, and assembly activities are underway at multiple sites in Norway and abroad. Additionally, we have successfully drilled the first HTHP well at Fenris. As we continue to execute according to plan, the total CAPEX estimate for our project portfolio remains unchanged. We maintain a strong financial position supported by high cash flow from operations. This enables us to invest in our profitable projects while also providing attractive dividends to our shareholders. We are also continuously optimizing our capital structure, and in early October, we raised $1.5 billion in the bond market, securing both 10 and 30 years maturities at excellent terms. Now, let's dive into the details, starting with production. We produced 450,000 barrels per day in Q3, slightly above our own expectations.
The production was down from the previous quarter due to planned maintenance, which affected Skarv, Grieg, Aasen, and Alvheim, reducing production efficiency across the portfolio to 88%, down from 95% last quarter. At Alvheim, the effect of maintenance was partially offset by the early startup of Tyrving, which came on stream in September. Johan Sverdrup, which I will discuss shortly, delivered stable production, while Valhall saw an increase driven by approximately 10% improvement in production efficiency. Overall, our year-to-date production performance has exceeded our initial expectations. And given the strong performance and the outlook for the remainder of the year, we now anticipate that the full-year production will land in the upper end of the previous guidance range of 420,000-530,000 barrels oil equivalents per day. As a result, we have updated our full-year production forecast to 430,000-440,000 barrels per day.
Now, let's turn to Johan Sverdrup, which accounted for over half of our production in Q3. This giant field, with nearly 3 billion barrels in initial reserves, last year increased its gross oil capacity to 755,000 barrels per day. Including gas production, the field has a total capacity of nearly 800,000 barrels of oil equivalents per day. And Aker BP holds a 31.6% stake in this exceptional asset, which is operated by Equinor in an excellent way. The third quarter production continued at an elevated level, contributing 237,000 barrels of oil equivalents per day to Aker BP. Operational performance at Johan Sverdrup has been outstanding, marked by consistently high production efficiency, exceptionally low production costs, and some of the lowest emissions intensity in the industry.
This year, our focus has been on optimizing water management while adding new wells, which has successfully extended the production plateau, now expected to continue well into next year. And next year, we plan to drill additional laterals from existing well bores to increase the reservoir exposure and mitigate water production. We are also approaching concept selection for phase three, which will involve subsea wells tied back to the Johan Sverdrup Field Center, with production targeted from late 2027. Johan Sverdrup is undoubtedly a remarkable asset and will remain a substantial contributor to Aker BP's production for many years to come. At Aker BP, we believe that maintaining low cost is essential to securing a competitive edge in the oil and gas industry. And we work systematically to achieve this, and I'm very pleased with both our efforts and the position we have established.
For the third quarter, production cost per barrel averaged $6.6, with a marginal increase from Q2, primarily driven by maintenance activities. Our performance over the first nine months of the year has exceeded our expectations, enabling us to lower our full-year cost guidance to $6.5 per barrel, down from $7 per barrel. In comparison to relevant industry peers, Aker BP's production costs remain highly competitive. And as shown in the chart to the right, data from WoodMac confirms that Aker BP has the lowest production cost among a group of 20 comparable companies. By driving cost efficiency and consistently delivering on our target, Aker BP is not only strengthening its resilience, but also positioning itself to deliver enhanced value for the stakeholders in any market environment. Aker BP has also established itself as a leader in low greenhouse gas emissions.
In the third quarter, our greenhouse gas emissions averaged 2.4 kilograms of CO2 equivalents per barrel, a marked improvement over the recent years. This progress is driven by enhanced energy efficiency and an increased share of production from fields powered from shore. The Q3 figure was positively impacted by changed production mix related to maintenance activities in the quarter. Now, this strong performance cements our standing as a global industry leader in greenhouse gas emissions intensity. Among approximately 300 of the largest E&P companies worldwide, Aker BP consistently ranks among the best in emissions intensity, as illustrated in the chart. This leadership position gives us a solid foundation for further emission reductions, and we are committed to continually reducing emissions from our operations. This is a core part of our strategy to achieve net zero emissions across our operations by 2030.
Beyond that point, we plan to offset the remaining emissions for nature-based carbon capture solutions. You've just had a chance to see some of the recent project activities across our company. Instead of only describing our ongoing initiatives, I thought it would be more insightful for you to view the different activities and progress we're making firsthand, and let me assure you, we are well underway in executing our extensive project portfolio, developing close to 800 million barrels of new reserves. This new ambitious program includes major developments like Yggdrasil and the Valhall Fenris, along with several tieback projects that strengthen our existing hubs at Alvheim, Grieg-Aasen, and Skarv, and notably, four of these tiebacks are already in production. Altogether, these projects will expand our production to over 500,000 barrels of oil equivalents per day in 2028.
The financial metrics are equally compelling, with an average break-even oil price of $35-$40 per barrel on an NPV 10 basis, an IRR of roughly 25%, and a swift one- to two-year payback at $65 oil price. Our projects are advancing on schedule, with a strong focus on fabrication, installation, and assembly activities, but drilling operations are also progressing well, particularly at the Fenris field in the Valhall area. This high-pressure, high-temperature reservoir presents more complex challenges than usual. However, we successfully batch-drilled the upper sections of all four wells in July. In September, we achieved a key milestone by drilling through the reservoir in the first well, and I'm pleased to report that the reservoir is meeting our expectations. We are now making good progress on drilling the second well, and this is exceptional work by the team in challenging conditions.
As I mentioned earlier, production at the Tyrving field and Alvheim area began in early September, five months ahead of schedule and below budget. Again, a remarkable achievement by our team and alliance partners. Tyrving is expected to contribute around 8,000 barrels per day net to Aker BP in 2025. In conclusion, we remain firmly on track to deliver our project on time, on cost, and with the right quality. Now, in addition to our ongoing project, we remain firmly focused on long-term growth. Over the past years, we have prioritized strengthening our capabilities in operations, drilling, technology, and project execution, all backed by robust alliances with our partners across the value chain.
These core competencies not only support the successful delivery of our current project, but will also serve as a competitive advantage as we unlock new growth opportunities and drive substantial value creation on the NCS over the next decade. Our strategy for expanding our resource base rests on three main pillars: increasing recovery from existing fields, acquiring resources, and successful exploration. We are actively pursuing each of these paths. First, regarding increased recovery, we have established a strong track record with assets like Alvheim, Skarv, and Valhall. By leveraging advanced technology, sophisticated reservoir management, and continuous improvement in drilling and operations, we have significantly expanded our resource base, consistently exceeding initial expectations. This approach remains a key value driver for Aker BP as we continue to mature the substantial opportunities in our 2C and 3P resource base.
Second, M&A has been instrumental in shaping Aker BP into the company it is today. Transformative deals with Marathon, BP, and Lundin have each played a pivotal role in our growth, and we continue to view M&A as an essential strategic tool for us in the future. Thirdly, exploration is central to our future growth. Very few activities can compete with the value creation potential of successful explorations. We are convinced that the NCS still holds significant untapped oil and gas resources. We have identified approximately 1 billion barrels of oil equivalents in net risked exploration potential near existing infrastructure. Our goal is to ensure that new discoveries become a profitable and foundational pillar for Aker BP's future, and I'm confident in our ability to achieve it. As always, our exploration strategy is pretty straightforward. It's about securing access to high-quality acreage.
We primarily achieve this through licensing rounds, where we are consistently ranked second in terms of number of licenses awarded, and additionally, we are actively engaged in the secondary market, optimizing our portfolio by trading licenses in and out of the portfolio. In addition, we are continually refining our skills, improving processes, advancing technology, and advancing competency. These efforts are aimed at increasing efficiency and success rates. One notable innovation is our AI-driven exploration robot, which has significantly enhanced our capabilities of analyzing complex data, inclusive of seismic data. We are also advancing our use of ocean-bottom node seismic technology, which we have successfully used for reservoir monitoring in produced fields. By collaborating with suppliers to make this technology more cost-effective, we aim to extend its application to exploration, enabling sharper subsurface imaging to identify exploration prospects more quickly and more cost-effectively, and lastly, we prioritize which wells to drill.
We have set an annual target of drilling 10 to 15 wells, with a roughly 80-20 split between near-field and standalone opportunities. By continually improving our exploration skills and driving technology improvements, we see a potential for significant value creation from exploration on NCS for many years to come. We here highlight our planned exploration activities from now through mid-next year, alongside some context around the program structure. One primary focus in the recent years has been the Skarv area. The Skarv FPSO is a state-of-the-art production facility, and our goal is to maximize its utilization by continually adding new tiebacks to the field. This began with the Ærfugl development a few years ago, followed by the ongoing Skarv satellite project, which incorporates several smaller discoveries.
Now, in September, we completed an exploration well in the area named Storjo, which yielded a discovery with a potential of up to 50 million barrels. We have three additional wells planned here in the coming quarters, alongside the maturation of new targets. We are also intensifying our activity in the northern North Sea, an area with promising prospectivity confirmed by recent discoveries. We have expanded our exposure through licensing rounds and farmings, with one well ongoing and five wells scheduled with a considerable follow-up potential, and early next year, we are set to drill back-to-back two of the most exciting wells on the NCS in the recent years, Bounty and Rondeslottet. Bounty was originally on our 2024 plan, but it's moved to Q1 2025 due to the rig schedule. This well, we will revisit an earlier discovery classified as non-commercial, testing a significant update potential from the original well.
Rondeslottet is, interestingly enough, also based on an older discovery and aims to assess where the reservoir quality improves as you move towards the crest of the structure. This well was initially planned for 2023, but operations had to be halted before reaching the target depths. On Yggdrasil area, we have four wells lined up, three of which will build on last year's successful East Frigg drilling. Altogether, we actually see a substantial upside potential of several hundred million barrels in this area.
Good morning. Aker BP's strong operational performance in the third quarter is also reflected in our financials. In the third quarter, we deliver a record high cash flow from operations of $2.8 billion, underscoring our ability to generate significant returns for our shareholders. We are also pleased to report that our development program continues at full speed, with investments in line with plan. As a result, we generated a free cash flow of $2.15 per share in the quarter, which can be compared to our quarterly dividend of $0.60 per share and represents a free cash flow yield of around 10% for the quarter alone at the current share price.
Moreover, we have further strengthened our financial position with low leverage and enhanced flexibility, ending the quarter with $4.1 billion in cash on account. In October, we also capitalized on a favorable market environment by issuing new 10 and 30-year bonds while repurchasing shorter maturities. This has further reinforced our liquidity position and extended our average debt maturity by three years. Finally, after another quarter of strong operational results, we not only raise our full-year production guidance to 4,030 to 4,040,000 barrels of oil equivalents per day, but we also lower our OPEX estimate to $6.5 per barrel, reinforcing our position as an industry leader in low-cost production.
Now, let's look into the key drivers behind the performance in the quarter. Starting with total income, sales volumes were lower quarter on quarter due to two key factors: reduced production caused by planned maintenance at the gas export terminals at SAGE and Kårstø, and an underlift, which temporarily impacted sales. It's important to note that over and underlift can fluctuate between periods, but these effects balance out over time. Realized liquid prices experienced a slight decline of 3%, driven by a 5% drop in Brent oil prices in the quarter, somewhat mitigated by stronger NGL prices and strong trading performance.
For gas, NBP and TTF day-ahead prices rose by an average of 11%. However, gas revenues decreased as we in the quarter had reduced production at Skarv and injected more gas at Grieg, Alvheim, and Sverdrup to maintain oil production during the mentioned planned shutdowns of the gas export facilities. Overall, total income for the quarter amounted to $2.9 billion. Moving on to the full income statement, production cost for the volume sold dropped to $186 million, though this figure is impacted by the underlift. On a normalized basis, production cost for the barrel produced amounted to $250 million, or $6.6 per barrel. I see this as particularly strong in a quarter with reduced production due to maintenance. Exploration expenses amounted to $40 million, down from $108 in the previous quarter.
Underlying activity remained relatively stable, and the reduction reflects lower dry well costs in the quarter as the Storjo discovery has been capitalized. In total, we achieved an EBITDA of $2.6 billion, which corresponds to a margin of 91%. Depreciation increased to $614 million, equating to $16 per barrel, up from $14.5 per barrel in the previous quarter. The increase was related to Ula, where reduced discount rates led to increased valuation of the abandonment provisions, which in Ula's case are directly charged to depreciation. Impairment totaled $304 million and was related to technical goodwill on Grieg, Aasen, Johan Sverdrup, and Valhall. After tax, our net profit ended at $173 million for the quarter. Note that, as in previous quarters with impairment of technical goodwill, we incurred an artificially high accounting tax rate since the impairment of technical goodwill is not tax deductible.
And remember, technical goodwill is an accounting mechanism that allocates goodwill to the asset level in M&A transactions, bridging the gap between the fair value and the tax value of assets. Impairment of technical goodwill is non-cash, and we expect to fully impair all technical goodwill over the field lifetimes. For those less familiar with this topic, we've included an illustration in the presentation materials and a video on our webpage, which we encourage you to review. Moving on to cash flows. Operating cash flow before tax and working capital was $2.6 billion in the quarter. Net taxes paid amounted to $424 million, significantly lower than in the previous quarter. In addition to only paying one tax installment in the third quarter, we also now see the benefits of our increased investment levels in 2024 in conjunction with the tax regime in Norway.
Additionally, we saw a decrease in working capital, mainly due to the lower trade receivables. This is, among other things, driven by the change from overlift to underlift in the quarter. In total, this resulted in a record high cash flow from operations of $2.8 billion. Total investments were stable quarter on quarter at $1.4 billion, resulting in free cash flow of almost $1.4 billion as well, or $2.15 per share. Net cash flow ended at $864 million, representing a 30% increase in our cash position to $4.1 billion. Note that our recent bond issuance was settled in October and will hence appear in the Q4 cash flow statement and balance sheet. Now, move on to the expected cash tax payments for the next three quarters, and as usual, we have included sensitivities regarding upcoming tax payments.
Note that the range is narrow, as we have already completed over nine months of the fiscal year. Hence, the oil price sensitivity applies to Q4 only. In October, we have made one additional voluntary tax payment, as you can see on the chart. And this is done to smooth out the tax payments between the second half of 2024 and the first half of 2025, which is basically a pure cash management decision to optimize interest cost. And for those of you who want to do your own estimates, I can recommend the Excel-based tax model, which is available on our investor webpages. Regarding our balance sheet, I'll focus on the key items related to our financial position. And thanks to the strong cash flow, our net debt decreased to $2.5 billion, with total bond debt standing at $6.7 billion.
One of the parameters we use to monitor our financial strength is the leverage ratio, which is calculated as net debt divided by the last 12 months' EBITDAX. And with an EBITDAX of nearly $12 billion, our leverage ratio stands at 0.2. And this is well within our internal target to stay below 1.5, providing us with substantial headroom and a lot of financial flexibility. Finally, our liquidity at the end of Q3 is exceptionally strong. In addition to our $4.1 billion cash position, our undrawn bank facilities bring our total available liquidity to $7.5 billion. As already mentioned, the Q3 accounts do not reflect the latest transactions we have done in the bond market, but I still want to provide some more details on this today. In late September, we launched a $1.5 billion bond offering split evenly between 10-year and 30-year maturities.
We also offered to repurchase bonds maturing in 2025 and 2026, with a combined take-up of close to $700 million. These transactions were completed in early October and will be reflected in our next financial report, and there are several reasons why I believe these transactions are worth highlighting. First, they represent a further improvement in our capital structure, increasing liquidity, and aligning our maturities with our business profile. We now have less than $300 million in debt maturing before 2028. The average maturity of outstanding debt has been extended from six to nine years and holds an average coupon rate of around 4%. Second, we are very pleased with the investor demand and thereby also the pricing of the bonds.
In terms of credit spreads, this was the best result in Aker BP's history, demonstrating the value of having a high-quality asset portfolio, prudent financial policies, and stable investment-grade credit ratings, and third, issuing a 30-year bond is a milestone for a Norwegian pure-play E&P company. It shows that the US bond market, with its high-quality institutional investors, shares our confidence in the long-term demand for oil and gas, the high attractiveness of the Norwegian Continental Shelf, and confidence in Aker BP's long-term strategy and value creation, and talking about value creation, this chart is one of my favorites. It encapsulates Aker BP's value creation plan from 2023 to 2028, and the left bar represents the accumulated post-tax cash flow from our low-cost operations over this period, shown across various oil price scenarios.
The next bar illustrates our uses of cash, with investments, including exploration and abandonment costs, depicted in black on an after-tax basis, covered at an oil price of less than $40 over the period. The pink bar then shows the cash flow available for debt service and dividends, and Aker BP's distribution policy is founded on resilience, and it reflects our financial capacity through the cycle. The ambition to increase the distribution by at least 5% annually through the current investment cycle remains firm, and with strong cash flow from low-cost operations and a solid financial position, we are confident in our ability to deliver on this ambition.
Now, before concluding the financial section, I will end by summarizing the updates to our full-year guidance. 2024 has so far been a year with excellent operational performance across both our operated assets and Johan Sverdrup. Now, with just two months remaining of the year, we are making some adjustments to our guidance. Production in the first nine months of the year averaged 436,000 barrels per day, well within the previous range of 420-440. With the maintenance season behind us in the third quarter, production is expected to recover in the fourth quarter. We raised the lower end of our guidance to 430 while maintaining the upper end at 440.
Production costs have also benefited from the strong operational performance. In the first nine months, we have achieved a cost of $6.3 per barrel, leading us to lower the full-year guidance to $6.5 per barrel, down from $7. Investments, exploration, and abandonment spend remain in line with our original expectations, and we keep the guidance unchanged. Now, that concludes the financial review for what has been another strong quarter for Aker BP, marked by record-high operating cash flow, improved financial flexibility, and positive adjustments to our full-year guidance metrics.
Thank you, David. And before we begin the Q&A sessions, I'd like to round off by summarizing our performance within the context of the Aker BP strategy. We continue to generate value for operational excellence, strategic investment in profitable growth, and disciplined financial management. We are executing on our growth project as planned, and we have lifted the bar for our full-year guidance parameters. Aker BP remains fully committed to delivering value to our shareholders through consistent dividends and long-term growth.
We will now take a short pause before opening the Q&A session. And to participate, please use the Teams link provided on the webpage. If you prefer to listen only, please stay tuned, and we will resume in approximately one minute. Okay, everybody, welcome back here in the studio. David and I have got myself a cup of coffee and managed to find a bit of paper so we could take notes of your excellent questions. And I'm assuming, Kjetil, that there are quite a lot of questions, so let's just keep going.
That's right, Karl. And the first question today comes from Matt Smith from Bank of America. Matt, please go ahead.
Hi, good morning. Yeah, thank you for taking my questions. I'd have a couple, please. The first would be on, so noting the comments you made on in terms of the project CAPEX costs, the budgets remaining unchanged. So, of course, you know, very positive reiteration there. I just wanted to touch upon sort of how you see the supply chain environment more broadly and your confidence on delivering these projects, not only on budget, but I suppose on schedule as well. That's really the sort of emphasis of that first question. So just how tight you see the various supply chains, the construction yards, that would be useful to get your thoughts on.
And then the second question, if I could, you know, thanks for all the detail on the latest bond issuance and the rationale, I suppose it's sort of my follow-on would be, you know, you've traditionally sat on a lot of liquidity, and of course, you still do now. I suppose, you know, why is that the right amount of cash to sit on? Does this link to M&A? Is it all about having optionality for that? And perhaps you could sort of offer your thoughts on the overall sort of macro environment, how active the market is, and what your appetite levels are, either from an acquisition or a disposal perspective at the moment, please.
Excellent. Thank you, Matt. So let's start with the project. And you're absolutely right. And let me reiterate the project. They are on schedule. They are on track to deliver, and they are on our cost or prognosed cost basis in U.S. dollars, as we previously talked about. And then your specific question as to where in the value chain there is more or less tightness. Reality is that we're now gone from a stage where we've set out a lot of these contracts to an execution and pre-assembly stage.
That means that quite a lot of this, call it market uncertainty, is now behind us, and we're now focusing on execution. That means that the discussions we have had around tightness and, let's say, lack of capacity is to a large extent history, and now it's almost purely about productivity and making sure that the different p ieces of this puzzle are at the right point in time, at the right place, at the right point in time, to put it very simply.
More specifically, well, right now, I mean, this is not necessarily related directly to the Aker BP project because we've already secured resources, slots at yards, pre-assembly yards, piping manufacturing, and so on, so right now, this is not tightness in the market. It's not a big issue for us. But if you were to come to the market with projects at this point in time, I would be concerned about the whole EI&T, electric installation, cable, transformers, et cetera, et cetera. And then your comment around bond issuance. And maybe, David, you could comment a little bit about the bond issuance and liquidity buffer, and I can comment a little bit about the M&A part of that question.
Yeah, no, I can definitely do that. So first of all, as I said in my presentation, very happy about that additional bond issuance that we closed 1st of October, providing a lot of additional liquidity. But I think it's more a holistic way of looking at the capital structure over time. So in addition to issuing new bonds, we also repurchased maturities in 2025 and 2026, meaning that we now have very little debt maturing over the next couple of years. In terms of what's the right level of liquidity for the company, I think we always want to have a prudent balance sheet. Financial capacity is important for us, considering, of course, the investment program, but also volatile market environments. So I think this puts us in an extremely good position for the years ahead.
And then your comments on M&A, and I'm not going to be specific about this topic, of course, but I sometimes get the question, are we in Aker BP overloaded and therefore don't really have the capacity to do an M&A due to projects? I can actually confirm that that is not the case. Right now, we're at a point in time where most of the, I would call, market maneuvering in the projects is behind us. And as you probably are aware of in the presentation, we're now putting more focus on the post-term 2027. And from your view, Matt, you should view that as, yeah, increasing focus on the look ahead and not the near-term issue. I think that reflects on our assessment of the current situation as well. Perfect. Well, thank you very much for all the detail.
Thank you, Matt. And then the next question today comes from John Olaisen from ABG. The floor is yours, John. Yeah, thank you for taking my question and congrats with strong Q3. In regards to Johan Sverdrup, Phase 3, you repeat that you hope to see the first production in late 2027. Could you tell us when do you have to hand in the PDO in order to reach this late 2027 startup? And also, could you give some indication of what Phase 3 will include, i.e., any new platforms? And also, will it add new reserves or is it just to produce the current reserves? That's my first question, please.
And my second question is regarding the most crucial phase of the Yggdrasil. What do you regard that to be of the development in terms of cost and timing for the startup? And my final question will be on the exploration program. I noticed that you are farming into the Arkenstone prospect with a 10% ownership. Equinor has recently stated that this is one of the most exciting wells in 2024 in Norway. So may I ask you, did you have to pay anything to farm into that? And also, could you, if you could give us some details on what attracted you to this, to the Arkenstone prospect, please?
Yeah, thank you, John. So I know I usually say that David can answer all the questions related to tax, but he's also actually responsible for non-operated assets in Aker BP. So to allow you to answer that one operational question today, David, you can talk a little bit about phase 3 on Johan Sverdrup?
Yeah, Phase 3 on Johan Sverdrup, yeah. So we are currently maturing the concept for Phase 3, and that's towards a final investment decision towards the end of next year. And when it comes to the concept, this is subsea infrastructure, which will allow us to drill additional wells and tie back to the existing platform. So we're not talking about new fixed platforms for Phase 3. And then with regards to reserves, yes, we will add some reserves, but it's also about making sure that we maximize production over the field. So this goes into the story around drilling wells to make sure that we have as many wells as possible, which is water-free, to maintain the plateau for as long as possible and also make sure that the decline once that comes is mitigated.
Excellent. And PDO? PDO, so FID towards the end of next year. Good. So Yggdrasil, I think that's where we are. The biggest topics. Well, I hate to say this, but actually Yggdrasil is going extremely well at the moment. I think the ones to watch is jacket installation summer of 2025. And then we are progressing very quickly on the power from shore, specifically the connections between our privately owned grid and the national grid in Norway. But let me be very clear. Yggdrasil is progressing excellently at the moment. Your question on Arkenstone, yeah, you're absolutely right.
We approach exploration through two different strategies. First, we apply for assets and we're consistently number two in number of licenses awarded, but also, and sometimes even number one in terms of operatorships. Then in the secondary market, we try to capture what we in a way didn't get. Arkenstone is certainly one of those prospects where we at least want to be exposed. What we've done there is a swap. That means we didn't really pay anything for it, but we swapped it for ownership interest in another prospect, which we, well, may not be that optimistic about.
May I ask which prospect that was?
Yeah, that was Kokopelli.
Thank you. Thank you very much. Good luck with Arkenstone.
Yeah, I hope so too.
Yes, thank you, John. And then the next question comes from Anders Rosenlund from SEB. Please go ahead.
Thank you. You give us the near-term exploration program in one of the slides, and gradually, at least I'm expecting more wells in the Barents Sea. Could you talk a bit about the Barents Sea and when the exploration program will contain more dots in that area? Is that a 2025 event or is it a 2026 event? And your thoughts on optimism about the Barents Sea as of now?
Yeah, so excellent question, Anders. So Barents Sea at the moment for Aker BP is focused on two key assets. The first one is, of course, the ongoing discussion around concept selection at Wisting, which is the key opener for a new infrastructure in the Barents Sea. And then we are collaborating with Equinor and Vår Energi to see if we can increase the gas volumes found in the Barents Sea to release new infrastructure. You will see some more of this.
Algol is one of these wells that are on the current drilling program. And as you progress into 2025, there might be two or three more that are being discussed with Equinor and Vår Energi. And in reality, the success of that set of wells, let's call that four to five wells, will determine whether or not there will be a follow-up in the western margin focusing on gas. So by the end of 2025, I think I'll be able to provide some more accurate answers as to the prospectivity of the western margin in the Barents Sea.
All right. Next one. Then we move on to the next question, which comes from Vidar Lyngvær from Danske.
Yes, thank you for taking my question. You maintain your NOK 5 billion CAPEX guidance for 2024, implying somewhat higher investment rate into 2025. Is there a reason to believe that you will continue on the Q4 run rate or should we expect a sequential drop into first half? That's the first question. The second question is, Tyrving, five months ahead of plan, how are we able to deliver so early and were ambitions just too conservative? Can we expect you to be similarly ahead of plan for the rest of the development portfolio? Is that in a different way? Is there potential for some of the 2026 projects to come on stream already in 2025, giving a bit of boost to the 2026 production trough? Thank you.
Yeah, so you want to talk about CAPEX prognosis, David?
Yeah, actually, Vidar, you dropped out a bit in the beginning, so I didn't catch the full extent of your first question. So if you repeat that, and then I think we heard well the Tyrving question.
Sure. The essence in the question on the CAPEX is that Q4 is implied to be a bit higher than the year-to-date run rate. Should we expect this to continue into first half 2025 as well, or could there be a sequential drop into as we start up next year?
No, I think in terms of production guidance for next year, we'll of course come back to that as part of our Q4 presentation in February. But I think it's fair to say that we're still in a ramp-up phase when it comes to CAPEX. And on Tyrving?
Yeah, and Tyrving, yeah, so in reality, the key drivers to delivering Tyrving's five months ahead of schedule is what I would call not even top quartile, but probably top 5% drilling performance. We always plan the wells to be top quartile. So it's not a matter of conservatism in the estimation. This is about excellent performance on behalf of the Drilling Alliance, which of course in this case consists of Odfjell and Halliburton, and then of course supported by our own teams. But I think it's very important to say that this is outstanding performance. That was followed up by similar performance from the Subsea Alliance, which in some has left us to start up some five months earlier and some 20% below CAPEX. Of course, this is driven by the fact that the production facility is already installed.
So as soon as you're ready, as soon as the wells are in place, as soon as the pipelines are laid and the connectors and subsea equipment is in place, you can start production. Now, if you look at that, the remaining portfolio we have, this is not generally the case, right? We are installing quite a bit of topsides, jackets, and other equipment that will actually mark the red line to production. So you shouldn't assume that this excellent performance necessarily means that we'll be able to accelerate some of the big greenfield projects. On some of the smaller tiebacks, I certainly hope that we'll be able to accelerate a little bit, yeah.
Great. Thank you for the color and good shout to the supplier.
Thank you.
Thank you, Vidar. Next question comes from Kate Somerville from J.P. Morgan. Please go ahead, Kate.
Hi, thank you so much for taking my questions. I have two, please. The first one is on the OPEX guidance. I noticed some of your competitors have reduced their guidance also. So I'm wondering if this is more of an FX impact or is there anything operationally that you've improved? It'd be great to go into detail on that. And then the second question is a bit high level. The last few months have obviously seen a lot of geopolitical macro volatility. Given that you have relatively low sort of cash break-evens on your projects, would that impact, would if that volatility continued, should we expect any change into your sort of future exploration or is actually you feel a bit more immune to that given those break-evens? Thanks.
Okay, let me start with OPEX. So the reason that we're reducing that from seven to six and a half is basically split in three. So first one, a little bit is because of the higher production. From the midpoint guidance has obviously gone up from the original guidance to the updated guidance. Then we have somewhat lower OPEX in absolute numbers than we assumed at the start of the year, mostly because of more effective turnarounds, but also because of reduced well maintenance. And then on the third matter, you're absolutely right. FX do play a part. But both are, I would say they're both about, they're all about equal. So one third in each will kind of give you a little bit of an idea of where we are.
That this will differ from operator to operator depending on what kind of OPEX they actually guided on and what kind of FX they guided on at the start of the year. And then volatility, and this is actually a really good question. So from an Aker BP perspective, we've always focused on operational excellence. Low cost, low OPEX, low cost per barrel, low CO2 emissions, and as low break-even as we can possibly get it. And that the simple rationale behind it is let's focus on what we can control, not on what we can't control. And I certainly can't do anything with the geopolitical and the macros in this world. But what I can do is to create a resilient company, which is well positioned to navigate those stormy waters.
And I actually hate to say this almost, but I'm a little bit. I have a little bit of ambiguity around that macro environment. On one hand, yeah, it'll be a bit painful for all the actors. But on the other hand, Aker BP has a track record for being countercyclical and grasping those crises when they appear. And there's a good saying that never wastes a good crisis. And right now, I think Aker BP is excellently positioned with low cost, low break-even, and excellent execution and fantastic operations to navigate those stormy waters should the y appear.
Very clear. Thank you so much.
Thank you. Then next question is from Victoria McCulloch of RBC. Please go ahead, Victoria.
Good morning. Thanks very much for your time. Appreciate it. A couple of questions from me. Can you provide us a reminder and an update of how Edvard Grieg is performing? It looks like production's been slightly weaker again in Q3, but also where infill drilling is planned for next year from memory. I think there's some more coming next year and what your expectations on that would do to production. Then maybe on Valhall, could you give us some of your base case assumptions for when Valhall plateau ends today? Does the extensions that we've seen and the positive commentary change any view on 2025? We've seen, we've not seen the production slide change very much from historically, but actually it seems to be some good production. Also with Tyrving coming on early, has that number changed in your minds? Thanks very much.
Yeah. So let me take Edvard Grieg first. Edvard Grieg, of course, have gone off of plateau and are now in the decline phase. This is, I would say, unfortunately normal. All oil and gas fields go through this phase. Previously, I would say that we have had a bit of a problem predicting exactly how that decline was performing, and that has led to some discussions around what the actual decline was versus the predicted decline. Now we have updated the model framework. We are spot on in terms of prediction, so now we are in control of the situation, and then the quarter-on-quarter reduction that you see now is slightly impacted by the turnaround that we see, but it's also a predicted decline, so next year, we are planning to drill infill wells.
My assumption is that they will contribute to production in 2025. The exact numbers will come back to when we guide in February 2025. But I think you should assume that quite a lot of what we do on Edvard Grieg is similar to what we've done on Alvheim, Skarv, Valhall to maximize recovery and fight decline on these fields. And then your question on Johan Sverdrup. Well, first of all, Johan Sverdrup is a fantastic asset. It has consistently overperformed our expectations all the way back to the startup in 2019. And as you've probably seen, we just, or the operator just announced that they have passed the 1 billion barrel mark.
We plan to drill, yeah, there are eight infill wells drilled or put on stream in 2024. We have two more ahead of us, one in Q4, one in Q1. And then in 2025, we will add about four retrofit MLT wells to the portfolio. So when I say well into 2025 in terms of Plateau, and I say Plateau with a little bit of an apostrophe, it's a reflection of the fact that we have underestimated the effect of those wells that we put on stream in 2024. So right now, I think that is the amount of color I can give to the production and Johan Sverdrup.
But let me reiterate that we think that the asset is actually really, really good. We've consistently overperformed on wells. We've consistently overperformed in terms of topsides and the processing capacity. And the regulation is world-class. Not regulation, but the regularity is world-class. And the operator is doing a stellar job. And then we are assessing the current direct impact. And as usual, we'll guide on that in February 2025.
Thanks. That coverage is really helpful. Appreciate it. Excellent.
Next caller is Teodor Sveen-Nilsen from SpareBank 1 Markets.
Good morning, guys. And thanks for taking my questions. I have three questions. First, very positive to see that developments are proceeding according to plan. But what has not gone as expected? I guess there must be something. Number two, that is on 2025 production, and I know you won't guide on 2025 production. But should we expect some decline given that not too many new projects will come on stream next year? Is it too conservative to model 10% decline on the overall production for 2025 versus 2024? And third question, that is, could you say anything about chance of success for the Rondeslottet and Bounty exploration wells? Thank you.
Yeah, so that has not gone according to plan? That's a good question, Teodor. Well, I think the key issues that we've been struggling that are past us is delivering of the big packages in the market at the moment, right? So this is about vendors that are essentially full. And we've been working with these vendors to make sure that we get a slot and that the delivery is on time, meaning that they are according to the site need dates. I would say that that has probably been the most difficult discussion that is now past us. But then I'll also say that we've actually been able to mitigate all these situations.
So right now, there's nothing that hasn't gone fundamentally not according to plan, but there are areas where we had to spend more effort to get it on plan. I think that's the way I would frame it. And then decline. Yeah, again, I think I'll reiterate and say that we'll guide on 2025 production as we always do in February 2025, and I won't provide any more commentary into the production guidance for 2025. Chance of success for Rondeslottet and for Bounty? Both of them are actually a little bit of the same story. So both of them are existing discoveries. In the case of Rondeslottet, of course, it's a tight reservoir. So we know that the volumes are there. What we're looking for here is actually where the permeability in the reservoir increases as you get towards the crest of the structure.
Bounty is an updip drill of a well drilled by ConocoPhillips, which had shows at the top of the reservoir. So again, here you're looking for an updip structure. So the discussions here are more along what is actually the cap. And so two very, very different assumptions. So when you talk about chance of success in Rondeslottet, we know that the oil is there and gas is there. It's more of a question of producibility, what we test. And then on Bounty, well, you should assume that we wouldn't have drilled this well if we don't assume this to be an interesting prospect. But as many of these high-risk, high-potential prospects, it's not a 50% chance of success, to put it that way. I'm not going to be very specific on what the actual numbers are or not, but they are sufficiently attractive for us to go into this.
Thank you.
All right. Then we move on to Sasi Chilukuru from Morgan Stanley.
Hi. Thanks for taking my questions. I had two, please. The first was on projects. You mentioned you're moving into the execution phase of the current development plan and focusing on post-2027 production. I was just wondering, when should we start seeing the next set of FIDs to support production post-2028? You already talked about the PDO on Johan Sverdrup Phase 3, but I was just wondering if you could talk about other projects that could potentially mature to FID in coming years.
The second was on the 2025 exploration program. You kind of maintained the guidance of targeting 10-15 exploration wells, but already you have highlighted 12 exciting prospects in the first half of 2024. I was just wondering what that means for 2025. Does it mean the 2025 exploration program could be much higher than these 15 wells, or does that mean the 2025 exploration program is much more concentrated towards the first half?
Yeah. So when it comes to projects and project FIDs, of course, we are dependent on a little bit of the development. But to give a little bit more color, Sasi, we've invested quite a lot in technology that should shorten the timeline from a discovery to us being able to make a decision. Three main components, maybe. The first one is a digital architecture that allows us to rapidly update reservoir models and, let's say, the decision basis for such decisions. Secondary, we're, alongside Landmark, developing something we call AAM, which is a framework that allows us to very rapidly make concept selection decisions, which is basically the early phase. In combination, those two technologies should allow us to make decisions extremely rapidly. In the Trell Nord case, it was a matter of weeks from exploration to we're actually able to production drill it.
On Frigg Øst, you've seen us already made the DG1, and we're well on our way to making the DG2, which is also, in terms of existing timelines, about half of the existing timelines, I would say. And then this will depend a little bit on how the framework develops. So we'd like to do this in campaigns because the last part of it is standardization. So as soon as you standardize on subsea systems, and then you can actually avoid a lot of the detailed engineering that currently takes a lot of time. We know what Christmas tree to use. We know what wells to use. We know what windows to use. So I am actually assuming that from a normal three to five years, we should be able to do this in one to two years. And then with smaller tiebacks, maybe less than a year.
That's at least the targets, right?
So that will depend a little bit on how the progress now in the exploration program and the IOR program develops. Then in 2025, if memory serves me right, I think we have 18 wells on the program. And the way we're guiding this on a 10-15 basis, think of this as a three-year rolling average because the drilling program per year will depend on the in-year capabilities or availabilities of rig slots, and they vary from year to year. So the way we think about this is that we prepare prospects, we put them on a rig line, and then whether they're actually on that rig line or not depends on what is happening on the rig line.
For example, if you have a discovery scope, which we've had quite a lot of in 2024, that means that a lot of the wells that were planned for 2024 is now pushed into 2025. So think of this as a guidance on a three-year rolling average and not as a specific year-on-year guidance of 10 to 15 wells. And then, Sasi, the 2025 exploration budget, and I'm not always excited about the exploration, but the 2025 exploration budget and plan is extremely exciting.
All right. Then we move on to Yoann Charenton from Bernstein.
Good morning, everyone. I would like to ask about CapEx, if you don't mind. So you have maintained your guidance for the year. While, during this earnings season, we have seen other large Norwegian E&P players lowering their CapEx guidance. And this was partly due to the persistent NOK weakness among other factors. This being said, are you able to comment on the weakness in the Norwegian kroner and the sort of savings you may have sort of achieved this year? And on the other end, what are the factors that have offset it? I'm thinking, for example, about potentially more spending on drilling at Sverdrup this year compared to your expectation as of October 2023.
Still within this broader, I will say, theme of CapEx, we have recently seen the Norwegian draft budget, and this has shown an increase in planned investment for several projects. This included Yggdrasil. You have also said during the call that drilling activity at Sverdrup should remain high next year, which was probably not entirely reflected in the base case scenario a year ago. So it looks like there are more upward CapEx pressure points than the other way around when thinking about your multi-year investment plan. So what I'm possibly missing here when thinking about this multi-year CapEx budget? And I will add one question, which is, let's say, moving back to production. Valhall production efficiency has increased to 90% in the third quarter, something we had not seen for a while. How confident are you in maintaining this production efficiency level in the coming quarters?
Okay, good. So let me start with a little bit of, let's say, high-level commentary around CapEx and guidance and the prognosis on the investment program. And then I'll leave it to David to talk about the FX effect. So when we made the investment decisions in 2022, and I think I've previously discussed this topic in similar calls as well, we did quite a bit of analysis on what we expected in terms of inflation, not necessarily on a global scale, but certainly on a, let's call it, category-to-category scale. That inflation was impacted by several factors.
The weak Norwegian kroner was part of it, which means that you're importing inflation into the Norwegian yards because a lot of, let's say, the input factors, even if they are invoiced in Norwegian kroner, are actually spent in euros. But it also led us to increase our expectation for inflation and, let's say, call it corrections due to capital effects significantly above the normal practice in the industry. And so when we go roll back now and say that this assessment was still valid, we're still on track in terms of delivering the project at the original budget in US dollars, this was actually the assessment we made.
And then some elements have been a little bit higher, some have been a little bit lower, but from an overall perspective, the assessment we did in 2022 are still valid. So that's why you see a difference in our way of talking about this compared to quite a few of the other players who have done more the industry practice of adding, let's call it, 2-2.5% of inflation, which is obviously the wrong number looking back from 2024 to 2022. Then if you want to comment on the direct impact on FX a bit, David?
Yeah, I don't know if there's too much to add to that, Yuan, because I think Kalle covered it quite well. So of course, we get a positive impact in dollars when a large part of our CAPEX spend is in Norwegian kroners, but then you get the opposite effect on that part, which is not in Norwegian kroners, and you're importing inflation, as Kalle said. So I think in general, when you look at our guidance for this year, we guided approximately $5 billion. That's where we ended. There's always a lot of moving parts. When I started guiding for this year in the start of the year, we talked about the possibility that some of the costs were being shifted due to deliveries of certain equipment and so on.
I think the key message here is that we are on plan in terms of what we planned in terms of activity, and the costs are also in line with that. And then when it comes to the national budget, I can't remember the specific way they actually do this, but I think they actually look at the actual inflation in Norwegian kroner compared to the original budget in Norwegian kroner as submitted in the PDO and then correct with that. So that should mean that all matters equal. You should see a difference from year to year about 5%-7%, even if the cost in U.S. dollars is flat.
And I can't remember what the national budget said, David, but I think that's roughly where you should be, actually. And then on Valhall and production efficiency, well, the production efficiency is calculated through four chokes: export, process, well, and reservoir. The issue on Valhall the last few years has always been the well choke, and that is due to solids influx into some of these wells because this is a chalk reservoir with fractured wells.
So we always had very high regularity on the process plants, at least back to 2020 when we started mitigating the little bit of a backlog on maintenance, et cetera, at Valhall. What you're seeing now is that we are better at predicting the solids influx in the wells and therefore able to do proactive interventions rather than reactive intervention. And that means that the well losses are going down, and that means that regularity is going up in terms of production efficiency. I think we're now at a level where I would say that I am actually happy with the performance on Valhall. And if we're as efficient in detecting solids influx in the coming years as we are today, we should expect the same type of production efficiency in Valhall in the future.
Thank you. That's good to hear. And just if I may, as a quick follow-up, because I referred in the questions to, of course, increased activity at Sverdrup in terms of drilling, is it fair to say that a year ago you were not expecting that much activity at Sverdrup as we have seen this year and as we are going to see next year as you hinted at during this presentation?
I think that's an erroneous statement, Yoann. So, what we have seen in terms of drilling activity when we're coming to the Q1 of 2025, we have completed the PDO scope. That means that this was actually the scope that was in the original PDO plan as it was submitted. Some of it we plan to execute in 2024, which has slid into 2025, which is the last well, which is the reason we're saying 41 wells, and Equinor is saying by year-end 40 wells. That's this last well that's gone from Q4 to Q1. And then we have known for quite some time the discussions around multilaterals.
The discussion has been, how many are we going to execute in 2024? And it's also the operator has been clear on. We're now executing four, which was already in our plan. But we certainly hope that these interventions, let's call it that, will be successful, and therefore we will add more of these interventions also in other wells during 2025. And the reason I'm saying that is, yes, of course, that will increase CapEx a bit, but it'll also be very positive in terms of production performance from the Johan Sverdrup field.
I appreciate the cutoff. Thank you very much.
Thank you.
Thank you. The next question comes from Matt Cooper from Barclays.
Good morning, and thank you very much for the presentation. So looking at the latest data, has Johan Sverdrup water cut increased per your forecasts, specifically those made at the time of the 2023 statement of reserves? And then second question, can you please remind us what recovery factor the current Johan Sverdrup 2P reserves imply? And what is the maximum recovery factor you think to be achieved at the field? And also the extra work that would be required to achieve this? And then finally, it looks like you have two really material wells being drilled early next year in Bounty and Rondeslottet. Would you be able to talk about the plan and the timeline for monetizing needs in the success case? Thank you.
I did not hear your first question with regards to Johan Sverdrup water. So if you could repeat that, please. We had some troubles with the sound.
Yeah, sure. So I'll just say looking at the very latest data that you've got, has the water cut increased per your forecasts? And specifically the forecasts that were made at the time of the 2023 statement of reserves?
Okay. So have the water cut increased more than what you expected in 2023?
But per reserves, measured against the total reserves or measured against the production prognosis?
So, just has the water cut for the field been in line with expectations? And I'm particularly talking about the expectations you had when you did the 2023 reserves booking for the field.
Yeah. So let's start with reserves. Okay, I think I understand where you're coming from. Sorry about that. So there are no changes to the reserves related to the discussions around the water production in this field. This is mainly a well debate about drawdown per well and how you distribute the drawdown across the 39 wells that are now in place and soon to be 41 wells. So it doesn't really have a reserve impact. Actually, the contrary, when you look at the reserves, the operator has now lifted their expectations in terms of, well, it's a target in terms of recovery to 75%.
That is actually quite a big gap because we already had a pretty ambitious PDO, depending a little bit on how you calculate the numbers. There are between 67.5%-72% existing recovery in the 2P reserves. And the reason is that this is an uncertainty calculation, right? So there's a stochastic variation in terms of how many barrels are in place actually against the 2P reserves. 75%, now you're getting quite close to what is probably theoretically possible in these kinds of fields. So that's a very positive view. And then the ultimate, of course, reserves will then be a function of the recovery rate and the oil-in-place volumes. And then we'll probably have to come back to that as the model matures and we get more and more data from the Johan Sverdrup field. But there are certainly no negative data at the moment.
If anything, I'll call it slightly positive. Yes, I think that answered your two first questions around water and 2P reserves. And then your final question was around Bounty and Rondeslottet and path to development and production if successful. That would depend on volumes. So Rondeslottet, if it's, they call it the low end of the economic space, will be a tieback to one of the hosts in the area. In that case, I would say within one to three years, we should be able to see an FID. If you have a big case, and let's call that more than four or five hundred million barrels, this will be a standalone, and you're probably talking about a timeline to FID more in the three to five year range, mainly because we'll have to do quite a bit of follow-up drilling to understand the well concept in detail.
And then Bounty, well, that's actually a little bit more difficult question to answer. Bounty certainly has a standalone potential. And if this is sufficient volumes for a standalone, you are probably talking about three-to-five years. It is a more conventional reservoir, so we know what wells to drill, we know how to model that, so it will have a shorter timeline. If it's on the smallest end of that scale, it'll be a tieback with a little bit of a shorter timeline to an FID. But again, it will depend a little bit on when do you actually need and want to make an FID, because if you're tying this back, it needs to be adjusted into the host and what is the physical capabilities of the host.
Very helpful. Thank you.
All right. Next caller is Oddvar Bjørgan from Carnegie. Please go ahead, Oddvar.
Yeah, thank you. Many investors are, of course, awaiting the startup of your huge development project portfolio in 2027. Is it possible to say a little bit more about the timing within that year? Can we expect some of the projects to start up in the early part of 2027, or should we expect most of it towards the end of the year?
It's a really good question. I think the answer is yes. Of course, inside 2027, and we're still on the phase where we're discussing the exact commissioning, ready for operation planning. But the subsea tie-backs will have a shorter timeline than the main fields. Yeah, some of it will start a bit earlier, some of it will start towards the end. We'll provide some more clarity on that as we approach these dates. It depends also, to be honest, about the marine plan for 2027 and how we're able to execute that.
Yeah, but Yggdrasil is performing well, I believe you said?
Yggdrasil is performing excellently at the moment, and the installation will be sometime summer 2027. And then it depends on how fast we can actually do the final hookup and commissioning before we start production. But I can assure you, Oddvar, nobody will be resting until we have actually started up production. We'll be as fast as we possibly can.
Thank you.
All right. Next is Mark Wilson from Jefferies. Please go ahead, Mark.
Good morning. Thanks for taking my question, guys. First question is, Equinor said last week that they expected Johan Sverdrup to be on plateau until early 2025. Obviously, today you said well into 2025. So, let's just confirm that is a change of commentary from both partners and just why this week versus last.
Yeah. Again, I think the reality, Mark, is that every time we made an assessment on the performance in Johan Sverdrup, we have erred on the conservative side. So when I'm saying well into 2025, it is an attempt to be more, let's call it expectancy-correct, on my commentary. And then what that will actually mean in months is a bit more difficult to say at the moment. But as I said, the program in 2024 has performed fantastically. There are two more wells to put in place, and we have four retrofit MLTs in 2025. The plant has performed better than expectation, both in terms of regularity, but also in terms of capacity versus nameplate. So I think my view on this is probably slightly more optimistic, if that is the right word to put or not, than what the operator has gone out and commented on.
Okay, that's very clear. Thank you. And so, yeah, you've got 39 wells there now versus you're going to have 41. You spoke about optimization across them and specifically water optimization having lower drawdown. So is this a fact of just having more wells to be able to spread the production across to reduce the water cut that others have spoke to, or are you seeing better performance on specific wells within that overall number? And that's me done. Thank you.
Yeah, yeah, yeah, actually, it's not a global issue, right? It's a well-by-well issue. So that means that some of this water is more concentrated around singular wells. So when I'm talking about optimization, there are basically two levels of optimization. The first one, obviously, as you're distributing the production capacity, in this case, 755,000 barrels of oil equivalent in oil capacity plus some 20,000 cubic meters of water across these wells. As you add number of wells, the drawdown on each well goes down, and the coning on each of these wells is slightly reduced. But then it's also an optimization game. So some of these wells would be better, have a better production index, as we call it, than the others.
And you want to distribute production to the wells that are water-free with a high production index and a well away from the wells that are delivering water with a lower production index, right? And the amount of wells that you actually have in that, let's call it high productivity index category, the higher the number of wells you have, the better it is. And so when I'm saying that we have overperformed, it means that we have actually, in the last few wells, delivered better on productivity index than we assumed, and therefore have more leeway in terms of optimization.
Very clear. Thank you very much. Excellent results beyond Johan Sverdrup as well. Congratulations.
Thank you so much, Mark.
Yes, thank you, Mark. And now, since we are 10 minutes after the plan, I think we have to close the call now. Any final words, Karl?
Well, thank you, guys. Thank you for calling in. Thank you for excellent questions. And thank you for following Aker BP. And then I wish you all an excellent day and a safe trip or safe endeavor, whatever you're doing. Thank you so much.