Aker BP ASA

OSE:AKRBP

Earnings Call Analysis

Record High Cash Flow and Strategic Growth

Aker BP has demonstrated significant financial strength in the third quarter, achieving a record operating cash flow of $2.8 billion, driven by robust operational performance and strategic investments. This success enabled the company to generate a free cash flow of $2.15 per share, which notably exceeds the quarterly dividend of $0.60 per share, illustrating strong returns for investors. The company ended the quarter with an impressive $4.1 billion in cash, reinforcing its liquidity and financial flexibility.

Production Levels and Adjusted Guidance

In Q3, Aker BP produced approximately 450,000 barrels per day, slightly above expectations but lower than previous quarters due to planned maintenance at key facilities. As a result, the company's production efficiency fell to 88%, down from 95% in the prior quarter. The company has revised its full-year production guidance, now expected to be between 430,000 and 440,000 barrels per day, reflecting an optimistic outlook for the remaining months of the year and a bounce back in production post-maintenance.

Cost Management and Operational Excellence

Aker BP reported a notable decrease in production costs, averaging $6.6 per barrel, which is competitive compared to industry peers and reflects effective cost management strategies. The company's operational efficiency has allowed it to lower its full-year cost guidance from $7 to $6.5 per barrel. These reductions are critical for maintaining profitability amid fluctuating oil prices and contribute to Aker BP's positioning as a leader in low-cost production within the sector.

Commitment to Shareholder Value and Future Growth

Aker BP remains focused on delivering shareholder value through a disciplined financial strategy, aiming for a minimum annual dividend increase of 5%. Investments are running in line with expectations, and the current operational model supports a strong dividend yield, making it an attractive option for investors seeking stability. The execution of growth projects is advancing as anticipated, with the potential to expand production to over 500,000 barrels of oil equivalent per day by 2028.

Innovative Projects and Sustainability Goals

The company is advancing key projects, including the Johan Sverdrup field, which has significantly contributed to production levels. Aker BP's emphasis on operational excellence is complemented by its sustainability initiatives aimed at achieving net-zero emissions by 2040. The company’s greenhouse gas emissions averaged a low 2.4 kilograms of CO2 equivalent per barrel in Q3, showcasing its commitment to environmental responsibility while maximizing production efficiency.

Exploration Plans and Strategic Investments

Looking ahead, Aker BP is set to enhance its exploration activities with an annual drilling program targeting 10 to 15 wells. This strategic focus on exploration is vital for discovering new resources and maximizing asset efficiency. The company is well-positioned to capitalize on exploration successes in highly prospective areas, thereby ensuring a robust pipeline of future production opportunities.

Positive Financial Outlook Amid Market Volatility

Despite geopolitical and macroeconomic uncertainties affecting the oil and gas sector, Aker BP’s strong financial footing and low cash breakeven levels provide a resilient framework for navigating potential market volatility. The company’s strategy centers on operational efficiency and cost management, positioning it to withstand external pressures while continuing to deliver value to its shareholders.

Earnings Call Transcript 2024-Q3

[Karl Hersvik, executive]

Good morning, everyone. With this intro from the successful installation and start-up of the tiering field. We welcome you to Aker BP's third quarter in 2024. It will, as usual, be given by our CFO, David Tonne; and myself, followed by a Q&A session. The [ Durbin ] 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, 5 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 lower 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 structurally drilled the first [ HD HP ] well at [indiscernible]. 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 about 10 and 30 year 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 start-up [indiscernible] 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 to 440,000 barrels of oil equivalent per day. As a result, we have updated our full year production forecast to 430,000 to 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 elevated level contributing 237 barrels of oil -- 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 have successfully expanded the production plateau now expected to continue well into next year. And next year, we plan to drill additional laterals from existing wellbores to increase the reservoir exposure and mitigate water production. We are also approaching concept selection for Phase III which will involve subsea wells tied back to the Johan Sverdrup 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 9 months of the year have 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 on the right, data from [ Wood back ] 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 has not only strengthened resilience, but also position 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 equivalent per barrel, a marked improvement in recent years. This progress is driven by enhanced energy efficiency and an increased share of production from fields powered from shore. The Q3 figure were positively impacted by changed production mix related to maintenance activities in the quarter.

This strong performance cements outstanding as a global industry leader in greenhouse gas emissions intensity among approximately 300 of the 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 0 emissions across our operations by 2040. This is a core part of our strategy to achieve net 0 emissions across our operations by 2030. Beyond that point, we plan to offset the remaining emissions for nature-based carbon capture solutions.

[Presentation]

[Karl Hersvik, executive]

You have 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 that we enclose to 800 million barrels of new reserves. This new ambitious program includes major developments like Brazil and the Valhall Fenris along with several tieback budgets that strengthen our existing hubs at Alvheim, Grieg/Aasen and Skarv. And notably, 4 of these sibacks are already in production.

Altogether, these projects will expand our production to over 500,000 barrels of oil equivalent per day in '28. The financial metrics are equally compelling with an average breakeven oil price of $35 to $40 per barrel on an NPV10 basis and an IRR of roughly 25% and a swift 1- to 2-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 [indiscernible]. This high-pressure, high-temperature reservoir presents more comp challenges than usual. However, we successfully [ batched ] the upper sections of all 4 wells in July.

In September, we achieved a key milestone by drilling food restaurant in the first one. 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 [indiscernible] field in Alvheim area began in early September. Five months ahead of schedule and below budget. Again, a remarkable achievement by our team and IS 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 strengthened our capabilities in operations, drilling, technology and project execution, all backed by robust alliances with the partners across the value chain. These core competencies not only support the successful delivery of our current budget, 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 [ rest ] on 3 main pillars: Increasing recovery from existing fields, acquiring resources and successful exploration. And 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 resort 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 yesterday. Transformative deals with Marathon, BP and London 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. And thirdly, exploration is central to our future growth. Very few activities can compete with the value creation potential of successful explorations. And we are convinced at the NCS still holds significant untapped oil and gas resources. We have identified approximately 1 billion barrels of oil equivalents in net risk 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.

And as always, our exploration strategy is pretty straightforward. It's about securing access to high-quality acreage. We primarily achieved this through licensing run 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 as a monitoring and 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 prioritized which wells to drill. We have set an annual target of drilling 10 to 15 wells with a roughly 20 split between near field and stand-alone 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 [ Alfa ] development a few years ago, followed by the ongoing scale satellite project which incorporates small -- several smaller discoveries. Now in September, we completed an exploration in the area and [indiscernible], which yielded a discovery with a potential up to 50 million barrels.

We have 3 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 for licensing rounds and farm-ins with one well ongoing and filed well schedule with a considerable follow-up potential. And early next year, we are set to drill back-to-back 2 of the most exciting wells on the NCS in the recent years, Bounty and Rondeslottet. Bounty was originally on our 2024 plan, but has moved to Q1 2025 due to the rig schedule. This well will revisit an earlier discovery classified as noncommercial testing a significant updip potential from the original well.

Rondeslottet is interestingly enough, also based on an older discovery and aims to assess where the reservoir quality proves 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. And on [indiscernible] area, we have 4 wells and up, 3 of which will build on last year's successfully [ tag ] drilling. Altogether, we actually see a substantial upside potential of several hundred million barrels in this area.

[David Tønne, executive]

Good morning. Aker BP's strong operational performance in the third quarter is also reflected in our financials. In the third quarter, we delivered 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 represent 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 3 years. And finally, after another quarter of strong operational results, we not only raised our full year production guidance to 430,000 to 440,000 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 2 key factors: reduced production caused by planned maintenance at the gas export terminals at SAGE and [ Costa ] and an underlift which temporarily impacted sales. It's important to note that over and on the lift 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 board facilities. Overall, total income for the quarter amounted to $2.9 billion. Moving on to the full income statement. Production costs for the volumes sold dropped to $186 million. Though this figure is impacted by the underlift. On a normalized basis, production costs 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 million in the previous quarter.

Underlying activity remained relatively stable and the reduction reflects lower dry well costs in the quarter as the studio 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. [indiscernible] where reduced discount rates led to increased valuation of the abandonment provisions, which in [ Ola's ] case, are directly charged to depreciation.

Impairments 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 noncash, 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 the video on our web page, 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, 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 3 quarters. And as usual, we have included sensitivities regarding upcoming tax payments. Note that the range is narrow as we have already completed over 9 months of the fiscal year, hence, the oil price sensitivity applies to Q4 only. In October, we have made one additional voluntary tax payments, 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 costs.

And for those of you who want to do your own estimates, I can recommend the [ XL ] based tax model, which is available on our investor web pages. 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 1.5x, 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 6 to 9 years and hold 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 U.S. 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 [indiscernible] group. Now with just 2 months remaining of the year, we are making some adjustments to our guidance. Production in the first 9 months of the year averaged 436,000 barrels per day, well within the previous range of $420 million to $440 million. With the maintenance season behind us in the third quarter, production is expected to recover in the fourth quarter. And 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 9 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 remains 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.

[Karl Hersvik, executive]

Thank you, David. And before we begin the Q&A session, 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 web page. If you prefer to listen only, please stay tuned, and we will resume in approximately 1 minute.

[Karl Hersvik, executive]

Okay, everybody, and welcome back here in studio. David and I have gotten myself a couple 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.

[Kjetil Bakken, executive]

And the first question today comes from Matt Smith from Bank of America. .

[Matthew Smith, analyst]

A couple, please. The first would be on [indiscernible] note in the comments you made in terms of the project CapEx costs, the budgets remain unchanged. So cost 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 do 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. 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've traditionally sat on a lot of liquidity, of course, you still do now.

I suppose -- 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? What your appetite levels are either from an acquisition or a disposal perspective at the moment, please?

[Karl Hersvik, executive]

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've now gone from a stage where we've set out a lot of these contracts to an execution and preassembly 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 pieces of this puzzle is at the right point in time, at 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 Aker BP project because we've already secured resources, slots at yards, preassembly yards, piping manufacturing, et cetera.

So right now, this is not -- tightness in the market, it's not a big issue for us. But if you were to come with to the market with projects at this point in time, I would be concerned about the whole ECI 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.

[David Tønne, executive]

Yes, 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 '25 and '26, 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 environment. So I think this puts us in an extremely good position for the years ahead.

[Karl Hersvik, executive]

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 project. 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 yes, you probably are aware of in the presentation, we're now putting more focus on the post 2027. And from your view, Matt, you should view that as yes, increasing focus on the look ahead and not the [indiscernible] issue. I think that reflects on our assessment of the current situation as well.

[Kjetil Bakken, executive]

And the next question today comes from John Olaisen from ABG.

[John Olaisen, analyst]

Congrats with strong Q3. In regards to Johan Sverdrup Phase III, you repeat that you hope to see the first production in late 2027. Can you tell us when do you have to handle the PDO in order to reach this late 2027 start-up? And also, could you give some indication of what Phase III will include i.e., in new platforms and also will reserve so it's just to produce the current reserve. That's my first question, please.

And my second question is regarding the most crucial phase of the [indiscernible]. What do you regard that to be of the development in terms of cost and timing for the start-up? My final question will be on the exploration program. I noticed that you are coming into the [ Arkansan ] prospect with a 10% ownership. Equinor has recently stated that this is one of the most exciting wells in 2024 in Norway. May I ask, 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 Arkansan prospect, please?

[Karl Hersvik, executive]

So I know I usually say that David can answer only questions related to tax, but he's also actually responsible for nonoperated assets in Aker BP. So to allow you to answer that one operational question today, David, you can talk a little bit about Scope 3 in Johan Sverdrup?

[David Tønne, executive]

Yes, Phase III on Johan Sverdrup. So we are currently maturing the concept for Phase III, 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 tied back to the existing platform. So we're not talking about new fixed platforms for Phase III. 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 fee to maintain the plateau for as long as possible and also make sure that the decline on that comes is mitigated.

[Karl Hersvik, executive]

Excellent. And PDO?

[David Tønne, executive]

PDO, So FID towards the end of next year.

[Karl Hersvik, executive]

Good. So [indiscernible], I think the -- where we are the biggest topics. Well, I hate to say this, but actually, [ Brazil ] 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, Brazil is progressing excellently at the moment.

Your question on [ Akinston ], yes, you're absolutely right. So we approach exploration through 2 different strategies. So first, we apply for assets, and we're consistently #2 in a number of licenses awarded. But also -- and sometimes even #1 in terms of operatorships. And then in the secondary market, we tried to capture what were in the way didn't get. And Arkinstone is certainly one of those prospects where we at least want to be exposed. So what we've done there is a swap so that means we didn't really pay anything for it. But we swapped it for ownership's interest in another prospect, which we -- well, maybe not that optimistic about.

[John Olaisen, analyst]

May I ask which prospect that was?

[Karl Hersvik, executive]

That was [indiscernible]

[Kjetil Bakken, executive]

And then the next question comes from Anders Rosenlund from SEB.

[Anders Rosenlund, analyst]

You give us the near-term exploration program in one of the slides. And gradually, at least I'm expecting more wells in 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 '26 event? And your thoughts and optimism about the Barents Sea as of now.

[Karl Hersvik, executive]

So excellent question, Anders. So Barents Sea at the moment for Aker BP is focused on 2 key access. The first one is, of course, the ongoing discussion around concept selection at [indiscernible] which is the key opener for our new infrastructure in the Barents Sea. And then we are collaborating with Ecuador and [ Wall ] 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 [indiscernible] of these wells that are on the current drilling program. And as you progress into '25, there might be 2 or 3 more that are being discussed with Equinor and [indiscernible]. And in reality, the success of that set of wells, let's call it, 4 to 5 wells will determine whether or not there would 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 balance.

[Kjetil Bakken, executive]

Then we move on to the next question, which comes from [indiscernible]

[Unknown Analyst]

You maintain your $5 billion CapEx guidance for 2024, implying somewhat higher investment rate. We look 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 [indiscernible] 5 months ahead of plan, how we're able to deliver so early and where ambition is just too conservative? Can we expect you to be similarly ahead of plan for the rest of the development portfolio. So in a different way, is there potential for some of the 2026 projects to come onstream already in 2025, giving a bit of boost to the '26 production trough?

[Karl Hersvik, executive]

So you want to talk about the CapEx prognosis, David?

[David Tønne, executive]

Actually, you dropped out a bit in the beginning. So I didn't catch the full cent of your first question. So if you repeat that, and then I think we heard well the [indiscernible] question.

[Unknown Analyst]

So 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?

[David Tønne, executive]

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 then on Tyrving?

[Karl Hersvik, executive]

Yes. And Tyrving, so in reality, the key drivers to delivering Tyrving 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 [indiscernible] 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. And then that was followed up by a similar performance from the subsea alliance which in sum has left us to start up some 5 months earlier and some 20% below capital.

And of course, it's 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 top sides, jackets and other equipments 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 here.

[Kjetil Bakken, executive]

Next question comes from Kate Somerville from JPMorgan.

[Katherine Somerville, analyst]

I have 2, 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, would be great to go into detail on that. And the second question is a bit high level. The last few months has obviously seen a lot of political macro volatility. Given that you have relatively low cash breakevens on your projects, would that impact would -- if that volatility continue, should we expect any change into your sort of future exploration? Or is actually you feel a bit more immune to that given those breakevens?

[David Tønne, executive]

Let me start with OpEx. So the reason that where you're reducing that from 7% to 6.5% is basically split in 3. So first one, a little bit because of the higher production. From the midpoint guiding has obviously gone up from the original guiding to the updated guiding. 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 bot. But both -- I would say that both about -- they're all about equal, so 1/3 in each will kind of give you a little bit of an idea of where we are.

And this will differ from operator to operate 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 a low breakeven 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 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, yes, a little bit painful for all the actors but on the other hand, Aker BP has a track record for being countercyclical and grasping those crisis when they appear. And there's a good saying that never waste a good crisis. And right now, I think Aker BP is excellently positioned with low cost, low breakeven and excellent execution and fantastic operations to navigate those [indiscernible] should they appear.

[Kjetil Bakken, executive]

Next question is from Victoria McCulloch of RBC.

[Victoria McCulloch, analyst]

A couple of questions from me. Can you provide us a reminder and an update of what and how [indiscernible] is performing. It looks like production has 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 are your expectations on that would deduction. And then maybe on [indiscernible] could you give us some of your base case assumptions for when pure plateau ends today, and does the extensions that we've seen and come at the positive commentary change on a view on 2025? We've seen -- we've not seen the production slide change very much from historically, but actually there seems to be some good production and also with the Tryvi coming on early. Has that number changed in your mind? .

[Karl Hersvik, executive]

So let me take Edvard Grieg first. So Edvard Grieg, of course, have gone off plateau and are now in the client base. This is, I would say, unfortunately normal. All oil and gas will go through this space. 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 predictions, and 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 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 start-up in 2019. And as you've probably seen, we just -- the operator just announced that they have passed the 1 billion-barrel mark. We plan to drill -- there are 8 wells drilled, infill drills or put on stream in 2024. We have 2 more ahead of us, one in Q4, one in Q5. And then in 2025, we will add about 4 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 [indiscernible]. It's a reflection of the fact that we have underestimated the effects 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 nuance level. But let me reiterate that we think that the asset is actually really, really good. We've consistently overperformance on wells. We've consistently overperformed in terms of top sides 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.

[Kjetil Bakken, executive]

Next caller is Teodor Sveen-Nilsen from Sparebank 1 Markets.

[Teodor Nilsen, analyst]

First, very posted 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 all 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 production for '25 versus '24? And third question that is, could you say anything about chance of success for the [indiscernible] the exploration wells?

[David Tønne, executive]

Yes. So what 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 on 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. Yes, 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 in production guidance for 2025. Chance of success for Rondeslottet and for Bounty. Well, 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 whether 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 reservoir so again, here, you're looking for an up-dip structure. So the discussions here are more along what is actually the can and 2 very, very different assumptions. So when you talk about chance of success in order not we know that the [indiscernible] is there. And gas is there. It's more of a question of producibility what we test. And then on Bounty, what you should assume that we wouldn't have drilled as well if we don't assume this to be an interesting prospect.

But as many of these high-risk have 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 not, but they are sufficiently attractive for us to go into this.

[Kjetil Bakken, executive]

Then we move on to Sasi Chilukuru from Morgan Stanley.

[Sasikanth Chilukuru, analyst]

I had 2, 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. Just wondering when should we start seeing the next set of FID to support production post 2028. You already talked about the onset of Phase III, but I was just wondering if you could talk about other projects that could potentially mature in coming years. The second was on the 2025 exploration program you kind of maintained the guidance of targeting 10 to 15 exploration wells but already have highlighted well exciting prospects in the first half of 2024.

I was just wondering what that means for 2025, does it mean the 2025 explanation program could be much higher than these wells or rates that 2025 exploration program is much more concentrated towards the first half?

[Unknown Executive]

Yes. So when it comes to projects and project FIDs, will, of course, be 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 time line from a discovery to us being able to make a decision. The main components maybe. The first one is a digital architecture that allow 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 the Nation, those 2 technologies should allow us to make decisions extremely rapidly. And in [indiscernible], it was a matter of weeks from exploration to actually able to production drill it. On fees, 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 time lines about half of the existing time lines, 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 vendors to use so I am assuming that from a normal 3 to 5 years, we should be able to do this in 1 to 2 years. And then with smaller bags, maybe less than a year. That's at least the targets, right? So that will depend a little bit on how it's now in the exploration program and the IR program develops.

Then in 2025, if memory serves me right, I think we have 18 wells on the program. And we're guiding this on a 10 to 15 basis. Think of this as a 3-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 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 rig line. For example, if you have a discovery scope, which you'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 3-year rolling average and not as a specific year-on-year guidance of 10 to 15 lots. 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.

[Kjetil Bakken, executive]

Then we move on to Yoann Charenton from Bernstein.

[Yoann Charenton, analyst]

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 all the large Norwegian E&P players lowering their CapEx guidance. And this was partly due to the persistent now quickness among other factors. This being said, are you able to comment on the weakness in the Norwegian krone and the sort of savings you may have sort of achieved this year. And on the other hand, what are the factors that have offset it? I'm thinking, for example, about potentially more spending on drilling at [ Vero ] 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 NovoGen [ drafted sets ] and this has shown an increase in planned investment for several projects.

This included [indiscernible]. 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 multiyear investment plan. So what I'm possibly missing here when thinking about this multiyear 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 have not seen for a while, how confident are you in maintaining this production efficiency level in the coming quarters?

[Karl Hersvik, executive]

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, call it category to category scale. That inflation was impacted by several factors. The weak Norwegian krona was part of it, which means that you are 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 that's when -- so when we go roll back now and say that this assessment was still valid, and we're still on track in terms of delivering the project at the original budget in U.S. 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% to 2.5% of inflation, which is obviously the wrong number looking back from 2024 to 2022. And if you want to comment on the direct impact on FX a bit, David?

[David Tønne, executive]

Yes. I don't know if there's to add to that, Yoann, because I think Karl covered it quite well. So of course, we will have positive impact in dollars when a large part of our CapEx spend is in ones. But then you get the opposite effect on that part, which is not in Norwegian kroners and you're importing inflation, as Karl has 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 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 national budget, 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 without. So that should mean that all matters equal, you should see a difference from here about 5% to 7% even if the cost in U.S. dollars is flat. And I can't read what the national budget said, David, but I think that's roughly where you should be.

And then on Valhall and production efficiency. Well, the production efficiency is calculated through 4 chocks, export, process well and reservoir. The issue on Valhall, the last few years have always been the well choke. And that is due to solid influx into some of these wells because this is a [indiscernible] well with fractured wells. So we always had very high regularity on the process bonds, at least back to '19, '20 when we started mitigating the -- a little bit of a backlog on maintenance, et cetera, what you're seeing now is that we are better at predicting the solid 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. So I think we are now at -- I think we're now at a level where I would say that I am actually happy with the performance on -- and if we're as sufficient in detecting solid blocks in the coming years as we are today, we should expect the same type of production efficiency in Valhall in the future.

[Yoann Charenton, analyst]

That's good to hear. And just if I may ask a quick follow-up because I referred in the questions to, of course, increase activity at [indiscernible] in terms of drilling. Is it fair to say that a year ago, you were not expecting that much activity at [indiscernible] as we have seen this year. And as we are going to see next year as you enter that [indiscernible]

[Unknown Executive]

I think that's a 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 per 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 in Equinor is saying by year-end 40 wells, that's the last well, that's coming from Q4 to Q1. And then we have known for quite some time, the discussions around multilaterals the discussion have been how many are we going to execute in 2024.

And as also the operator has been clear on, we're now executing for, which was already in our plan. But we certainly hope that this 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 will also be very positive in terms of production performance from [indiscernible]

[Kjetil Bakken, executive]

The next question comes from [ Matt Cooper ] from Barclays.

[Unknown Analyst]

So looking at the latest data, as [indiscernible] increased earlier 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 [indiscernible] and why is the maximum recovery factor you think we achieved in the field and also the extra work that we required to achieve this. And then finally, it looks like you have 2 really material wells being [indiscernible] early next year, [indiscernible]. Would you talk about the plan and your time line for [indiscernible] you do the success as?

[Unknown Executive]

I did not hear your first question with regards to Sverdrup Water. So if you could repeat that, please, we had some troubles with the sound.

[Unknown Analyst]

Yes, sure. So I just say looking at the very late state that you've got, has the work increase per your forecast and specifically, the forecast that were made at the time of the 2023 statement of reserves.

[Unknown Executive]

Okay. So have the water cut increased more than what you expected in 2023. But per reserves measured against the total reserves are measured against the production prognosis.

[Unknown Analyst]

So just as the water cut for the field to be in line with expectations, and I'm particularly talking about the expectations you had when you did the 2023 reserves booking for the field.

[Unknown Executive]

Yes. So let's start with users. Okay. I think I understand what you're coming from. Sorry about that. So there are no changes to the reserves related to the discussions around the water production in the field. This is mainly a well debate about drawdown per well and how you distribute the drawdown across the 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 -- or let's say, target in terms of recovery to 75%.

And 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% to 72% existing recovery in the 2P reserves. And the reason is that this is an uncertainty calculation, right? So this is a sarcastic 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 kind 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 Johan Sverdrup. But there are certainly no negative data at the moment. If anything, I'll call it, slightly positive.

Yes. I think that answered your 2 first questions around water and 2P reserves. And then your final question was around...

[Unknown Analyst]

[indiscernible] path to development and production, if successful.

[Unknown Executive]

That would depend on volumes. So [indiscernible], if it's we 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 1 to 3 years, we should be able to see and FID. If you have a big case, and let's call that more than 400 million, 500 million barrels, this will be a stand-alone and you're probably talking about a time line to FID, more under 3 to 5 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 is -- that's a pretty -- I said actually a little bit more difficult question to answer. Bounty certainly has a stand-alone potential. And if this is sufficient volumes for a stand-alone, you are probably talking about 3 to 5 years. It is a more conventional reservoirs. So we know what wells to drill. We know how to model that. So it will have a shorter time line. If it's on the smaller end of that scale, it will be a tieback with a little bit of a shorter time line to an FID.

But again, it will depend a little bit on when, 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.

[Kjetil Bakken, executive]

All right. Next caller is Oddvar Bjørgan from Carnegie.

[Oddvar Bjørgan, analyst]

Yes. 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 '27 or should we expect most of it towards the end of the year?

[Unknown Executive]

It's a really good question. I think the answer is yes. Of course, inside 2027, we're still in the phase where we're discussing the exact commissioning, ready for operation planning. But the subsidy tiebacks will have a shorter time line than the main fields. Some of it will start a bit earlier, somewhere of it will start towards the end. We'll provide some more clarity on that as we approach these states. It depends also, to be honest, about the Marine plan for 2027 and how we were able to execute that.

[Oddvar Bjørgan, analyst]

Yes, with [indiscernible] is performing well, I believe you said.

[Unknown Executive]

[indiscernible] is performing excellently at the moment. And the installation [indiscernible] 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 again, I assure you, Oddvar, nobody will be resting until we have actually started up production. I will be as fast as we possibly can.

[Kjetil Bakken, executive]

Next is Mark Wilson from Jefferies.

[Mark Wilson, analyst]

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?

[Unknown Executive]

Yes. Again, I think the reality, Mark, is that every time we made an assessment on the performance in Johan Sverdrup, we have heard 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 whether -- 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 2 more wells to put in place, and we have 4 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 it out than what the operator has gone out and commented on.

[Mark Wilson, analyst]

Okay. That's very clear. And so you've got 39 wells there now, you got 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 I spoke to, or are you seeing better performance on specific wells within that overall number. And that's me done.

[Unknown Executive]

Yes, 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 content around singular wells. So when I'm talking about optimization, are basically 2 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 that draw down on each well goes down and the coning on each of these wells are slightly reduced. But then it's also an optimization game.

So some of these wells would be better, have 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 water 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 are actually in the last few whiles delivered better on productivity index than we assumed and therefore, have more leeway in terms of optimization.

[Kjetil Bakken, executive]

Yes. Thank you, Mark. And now since we are 10 minutes after plan, I think we have to close the call now. Any final words, Karl.

[Karl Hersvik, executive]

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.