Good morning, and welcome to this presentation of Aker BP's fourth quarter and full year 2023. Joining me today are CFO David Tønne, our Chief Digital Officer Paula Doyle, and Per Øyvind Seljebotn, Senior Vice President for Exploration and Reservoir Development. Together, we aim to provide insight into the performance and outlook for Aker BP, focusing on our strategic priorities. Following the presentation, we will, as per usual, have a Q&A session. 2023 marked the first full year as one integrated team and portfolio after the acquisition of Lundin, and I'm pleased to report that we have successfully met all operational and financial targets. Field developments are on track, and we are progressing well with the project launched in December 2022. The key milestones were achieved on schedule, main contracts have been placed, and capacity secured. We are on schedule and on budget.
Furthermore, we delivered exploration success, notably with the Frigg East discovery in the Yggdrasil area. With high-quality assets and an organization committed to continuous improvement, we have further reduced emissions intensity from an already industry-leading level. On the financial front, robust cash flow and capital discipline allowed us to strengthen the balance sheet and increase dividends. Now, let's look at the numbers. In 2023, we produced 457 mboepd. That is the highest in the company's history. Production cost was $6.2 per barrel, the lowest ever, and highly competitive in an industry context. And our emissions were only 2.8 kilograms per barrel produced. This is the lowest ever for Aker BP, and also amongst the lowest in the, across the industry. So what is the main driver behind this strong improvement?
Of course, the Lundin portfolio, which gave us an increased share of Johan Sverdrup, is very important. But we also see positive contributions from improvements across the portfolio as we continue to roll out new digitization initiatives and as we drive efficiency throughout the value chain together with our alliance partners. This operational performance also translated into strong financial results. We report the total income of $13.7 billion, which is, of course, also a new company record, and 5% above 2022, even with 20%-30% lower oil and gas prices. Cash flow was strong, even without adjusting for the elevated tax payments in the first half of 2023, which of course, is related to the much higher oil and gas prices in 2022.
We paid $2.2 per share in dividends as planned, which equals around 70% of our free cash flow for the year. This table summarizes our guidance compared to the actual 2023 numbers. The production of 457,000 barrels per day was in the very high end of our original guidance of 430-460. Compared to the initial estimates, the outperformance came from Johan Sverdrup and Ula. We updated and narrowed the guidance after Q3 to 455-465, but during Q4, we had an unexpected shutdown at Alvheim, which put us in the low end of this updated range. Still, in sum, we have every reason to be satisfied with the 2023 production. The production cost of $6.2 per barrel was far lower than we expected a year ago.
This reflects both strong operational performance, but also lower electricity costs than anticipated and a somewhat lower drilling activity than planned. In addition, we were also helped by the currency effects. A significant part of the cost is based in Norwegian kroner, hence, we gained from a strong US dollar. Our CapEx, the key message is that we delivered as planned, reflecting that the projects are on track. Aker BP's strategy has always been based on the core belief that oil and gas prices will remain volatile. In the long run, the winners in this industry will be the companies producing at the lowest cost, with the lowest emission, and with a robust financial robustness to withstand the down cycles. Now, this is why we have focused on building a portfolio of quality assets, supported by a robust financial position and an organization that focuses on continuous improvement.
Now, at the beginning of 2024, the world is presenting our industry with some additional challenges. One of these is the security situation. The geopolitical arena is rife with conflicts, such as the war in Ukraine, the Israel-Palestine situation, and the tension in the Middle East. Aker BP is impacted by these conflicts in several ways. In addition to the obvious impact on the oil market, this also impacts our supply chain as raw material sources and shipping patterns are affected. This is an important factor when we decide where and when to source the input factors. But I must say, I'm actually highly impressed by the way the project teams and supply chain organization have tackled these ongoing challenges and avoided disruptions to the project execution. Another area of concern is the global economic situation, which is characterized by inflation and increased interest rates.
This also impacts our business. Before we launched the current investment program, we performed a comprehensive analysis to understand the inflationary pressures across the value supply chain. We also made some very conscious decisions on which risk we were willing to take and which ones we should aim to mitigate. So far, this strategy has been successful, as the CapEx estimates are basically unchanged. On the list of challenges, I must also, of course, mention the ongoing energy transition. The transition to a low-emission world will require massive investments in cleaner energy solutions. Meanwhile, all realistic scenarios show that oil and gas will remain an important part of the global energy mix for decades. But as the energy transition gains momentum, the cleanest and most efficient oil and gas producers will be best positioned to thrive, and we want to be one of these companies.
Aker BP's approach is simple and constructive. We will contribute to the energy transition in three ways. Firstly, our value creation will generate capital for the owners and for society, which can in turn be redeployed to support the innovation and development of new green energy. Secondly, we will contribute directly by minimizing our own greenhouse gas emissions. I will come back to our strategy on this topic in a few moments. Thirdly, as we continuously chase improvements, we are developing new technology and new knowledge that we aim to share with other companies and industries, and play an active part in the innovation that is needed to solve the problem. Now, speaking of technology and innovation, one topic that is on everybody's lips these days is digitalization and artificial intelligence.
This is a big thing, and I have long been convinced that artificial intelligence, or AI for short, will enable changes that lie beyond our current imagination. For nearly a decade, Aker BP has held the core belief that effective digitalization can drive radical improvements in the way we explore, develop, and produce oil. Digitalization has therefore been the key element in our improvement agenda, and I'm very confident that Aker BP is well-positioned in this domain. Our improvement journey started 10 years ago and found its current form in 2016, focusing on 4 primary areas. And while these 4 areas have gradually merged into a whole, we still live and breathe by the same principles which have served us well. In terms of strategic alliances, we build a one-team culture, where our main supplier is based on common goals and shared incentives.
We're working on lean operation, which is basically a framework for developing efficient work processes. We focus on business, flexible business model, which is about rethinking how we structure our interactions with suppliers and business partners in order to increase productivity. And not least, digitalization, an essential enabler for building the EMP company of the future. When we started on the digitalization journey, there were no readily available solutions to transform an analog oil and gas company into a digital champion, so we started from scratch. And we co-founded Cognite, which has since become a world-class industrial software company, serving hundreds of customers across multiple industries. This has helped us to gather and liberate all our data, and today, we are actively using this data, not only for quick access to information, but also to improve our operational efficiency with data-driven work processes and automation.
We have established digital workspace that stimulate cooperation and save massive amounts of time, and we've created an environment that stimulates creativity and innovation. Who knows what can be achieved when we add AI to this mix? Now, to underscore the importance of digitalization, we have organized it as a separate business unit within the company. This unit is headed by Aker BP's Chief Digital Officer, Paula Doyle, who are with me here today. Paula, maybe you could share with the viewers Aker BP's perspective on digitalization.
My pleasure, Karl. So to be clear, we have a very clear vision for Aker BP, and that is to be the world's first data-driven oil and gas company, and we are well on our way. There is no doubt that there is tremendous opportunity for optimization in our industry, and a lot has happened from a digital perspective in the last decade. Yes, a little slower in industry than consumer, but we're getting there. Things have happened both in Aker BP itself and also externally: the rise of cloud, analytics, AI, DataOps platforms, et cetera. This has meant that we have been able to, along with our digital ecosystem, do foundational work in modernizing our tech stack, getting ready for rapid tech development, growing and strengthening our ecosystem, and proving that we can deliver actual, measurable business value from digital. So where are we going?
Well, our focus remains on getting to a state where we have seamless data flow along our value chain, from exploration to production. The reason we want to achieve this is because we know that with quality, trusted data available to humans, machines, including AI, we can refactor workflows to increase decision speed and increase decision quality. Some examples of this are what we are doing with Stimline, and you'll see IDEX later. The work we're doing on collaborative and digital well planning and ensemble modeling are also great examples of how we have deployed technology and changed the way we work to drive better business outcomes. Of course, getting data quality up to scratch in industrial environments is not for the faint-hearted, and luckily, we've been working on this for some time, and now we see how we can use GenAI to turbocharge this.
We're currently working with Cognite on a GenAI tool that is enabling us to automatically populate our master data, from documents to data, leveraging AI. Again, it's a new way of working that both saves cost for that workflow itself, but also future cost by improving quality. We have big plans for Yggdrasil. It will be the first digitally native oil and gas platform, and what I mean by that is we are building the digital twin as we are building the physical platforms.
This digital twin is currently being populated by our alliance partners with the data they are creating right now during engineering and construction, and it will be the basis for a digital operating strategy, powering remote operations, smart contracts for predictive maintenance, and high degrees of automation to ensure that we will be able to operate this highly complex offshore facility at low cost and unmanned two years after startup. We all know that tech development is rapid, and we aim to be at the forefront. GenAI exploded into the workplace early 2023, faster than we've ever seen a new technology transition from consumer web to work. We saw this early, and we've used the last year to build competence, opinions, and actual tools that we're using today. An example of this that you'll also see later is Exploration Robot. So we're just beginning, so expect more.
Our goal is clear: become data-driven, and also clear is our strategy for how to get there. Number one, focus on business value. We're deliberately driving digital initiatives with handshakes with our assets for value outtake. Number two, strengthen the ecosystem. We are working with Norwegian and global partners for their product development. We want them to use our knowledge to develop useful products that the market is interested in buying. Number three, build our competence. We're lucky we're able to attract really talented people to Aker BP, and we know that we need internal competence to take the right strategic and tactical steps. And number four, get the quality, trusted, fresh data flowing, and then we can do magic.
Thanks, Paula, and I really look forward to the next 10 transformational years as the E&P company of the future. This is an outline of Aker BP's strategic priorities and shows how we plan to achieve our goals, which remain consistent with those established in mid-2022, following the completion of the Lundin transaction. Our focus is on operating safely and efficiently with a parallel commitment to decarbonize our business. We have a significant task ahead of us, executing our large project portfolio, while at the same time, we continue to build new growth options for the company. And ultimately, we aim to accomplish these objectives in a manner that maximizes value for both our shareholders and society. Now, we will delve into the performance and outlook for each of these priorities in turn.
Aker BP is a pure-play oil and gas company, solely focusing on activities within the Norwegian Continental Shelf. Now, for the benefit of those of you who are new to Aker BP and new to our story, we will provide an overview of our portfolio. We produce oil and gas from 6 field centers, and our resource base exceeds 2.5 billion barrels of oil equivalents, with over two-thirds classified as 2P reserves. In 2023, 86% of our production was oil and NGL, while 14% was gas. Keeping people safe is a fundamental goal and a top priority for Aker BP, and as I've reiterated on numerous occasions, we firmly believe that high safety and operational excellence are two sides of the same coin.
Over the years, we've made significant improvements in this area, and therefore, I am not satisfied with the safety performance in 2023, even if we compare well within the industry. The number of personal injuries increased, raising the TRIF indicator to 2.4. We had three incidents categorized as serious during the year, resulting in an improved SIF indicator of 0.3, down from 0.7 in the previous year. Fortunately, none of these incidents reached a high severity, but the bottom line is that they should not have occurred at all. Each incident, as always, therefore, thoroughly investigated to extract lessons and implement preventive measures to ensure they do not happen again.
With the acquisition of Lundin in 2022, we doubled the production level, and as I mentioned, in 2023, Aker BP produced 457,000 barrels per day, which was on the high end of the original guidance for the year. Now, as the chart shows, the largest contributor to this growth was the ramp-up of Johan Sverdrup, and I'm also pleased with the startup of Frosk and Kegg in the Alvheim area, with Kegg actually being 5 months ahead of schedule. In the second half of the year, production was impacted by both planned and unplanned shutdowns at Alvheim, Valhall, and Skarv. We also saw a decline at the Edvard Grieg field. While Aker BP is a proud operator of most of its assets, there is one important exception. We own 31.6% of the Johan Sverdrup field.
Johan Sverdrup is simply a fantastic success story. With almost 3 billion barrels of recoverable oil, it's one of the largest field ever found in Norway. The development of both phase one and phase two were carried out in an excellent way by the operator, Equinor. The production level has since been increased several times to a level nearly 100,000 barrels per day above the original design capacity, and the field has been operated with industry-leading performance, safety, regularity, cost, and emissions. In 2024, we plan to drill the remaining PDO wells. Equinor is also actively working to mature more infill wells and further subsea developments on the flanks of the field. The operator currently expects to be able to maintain the current elevated production level until late 2024 or early 2025. We have catered for this timing uncertainty in the production guidance for 2024.
Production efficiency, or PE for short, is one of the most important performance indicators, measuring the overall capacity utilization of our operated assets. In the recent couple of years, we have observed a positive trend in production efficiency, and for the full year of 2023, we achieved a PE of 92%, even with a significant amount of planned and unplanned downtime in the second half of the year. At 92%, we still remain well within the top quartile in the industry, according to benchmark studies. However, we aim higher, and our long-term ambition is to reach 95%. As illustrated earlier, the production cost per barrel has been significantly reduced over the past five years. The startup of Johan Sverdrup plays an important part with a unit cost of around $2 per barrel.
Nevertheless, Aker BP's asset base remain highly competitive, positioning us favorably in comparison to industry peers. In fact, we rank as the lowest in this group of relevant comparisons. It is tempting to view this as a result of our continuous improvement efforts that's been ongoing over years. A prime example of this improvement focus is within well interventions.
It looks easy, but it's definitely not for everyone. Ski jumping is like intervention in our industry. It looks easier than it is, and although many things are the same as 30 years ago, there's been some major changes, not the least in technology and equipment. The distance from me here to the Oslo Fjord is almost identical to the longest wells on the Valhall field. With a pipe this size, it doesn't take much for the production to be reduced or stopped entirely.
Although many things are done in the same way as 50 years ago, there have been revolutionary changes in well intervention, as in ski jumping. For instance, well diagnostics used to take place using pen and paper and a checklist that had to be handed to others physically before the work could proceed. Hundreds of emails, Excel sheets, Word documents, and PowerPoints for each operation gradually became unmanageable. Now, this takes place digitally in real time, and partly by the means of autonomous operations, which reduce the number of exposed personnel.
We perform almost 100 operations a day. This meant that we had to develop an interactive platform tailored for interventions to ensure a more structured and better way of learning.
Together with Stimline, the alliance partners Aker BP, Stimwell, and SLB have implemented a tool, IDEX. It enables everyone to work in the same way and to have access to exactly the same information everywhere. This way of working also makes it easier for us to predict where production strings problems are likely to occur and how to prevent them. Based on historical data, the program also provides a fair estimate of how long it'll take to perform the necessary maintenance work.
This interactive platform makes it possible for us, as a service provider and alliance partner, to retrieve the information that we need in a second. This data is used to feed our AI model that enable autonomous operations. We are not on this autonomous journey just to sound cool and fancy. We do it because it's safer and because it enhances predictability in our operations. Wireline and coiled tubing operations are the operations we perform most frequently. These are now autonomous, just like autonomous cars. The driver still has full control of the car and sits in the driver's seat, for now at least.
We have now shown that this works in our operations at Valhall, and one thing is for sure, we could never have done it alone. It's the alliance which is the key ingredient in enabling us to be the first in the world to do this.
This alliance is huge to us because it's a relationship that's based on creating value and a relationship based on trust. You can see with an alliance like this, we have been able to accelerate technology, accelerate digital developments, and create new workflows. This takes intervention, which has been in the dark ages, into a very bright future.
Using sensors and real-time modeling ensures that we can optimize the use of existing equipment on all our assets. This is merely the first step in a transformation towards fully autonomous operations. We have matured our digital transformation, and we aim to be even more proactive, maximizing value by ensuring we are working on the right well at the right time in a predictable and robust manner.
You have now seen one example of how we use digital solutions to optimize the operations, and we do this in collaboration with the best partners in the industry. The IDEX collaboration platform is very useful for us, and it's now in operation in most of our assets. This was only one example. There's a lot of innovation going on across various fields in Aker BP, where we modernize the way we work. The common thread in all these initiatives is a strong emphasis on creating value. Each initiative comes with its own plan, aiming to achieve at least one of three goals: cutting costs, boosting production, or reducing emissions. We have, over the last few years, sharpened the focus on decarbonization, and we have a clear plan to achieve net zero Scope 1 and 2 emissions by 2030.
The initiatives to get there can be grouped into three main categories. Firstly, we will avoid emissions wherever possible. This can be done through electrification or through portfolio optimization and asset retirement. Second, when avoidance is too expensive, we aim to minimize emissions through more efficient use of energy on our fields and operations. And thirdly, we will neutralize the remaining emissions through high-quality forestation or other carbon removal projects. We already have a significant portfolio of such projects to build on. Now, when it comes to Scope 3, which are the indirect emissions in the value chain but outside the company, we have so far focused on the upstream part, and we have managed this through our procurement processes. Carbon capture and storage, or CCS for short, is expected to play an important role in the energy transition, and the Norwegian Continental Shelf holds significant potential for CO2 storage.
Last year, we were awarded a license for carbon storage, and we're currently maturing this opportunity towards a drill or drop decision. Now, this is the strategy. Let's turn to how we are performing. As highlighted at the beginning of the presentation, Aker BP's greenhouse gas emissions in 2023 were below 3 kilograms of CO2 equivalents per barrel produced, half of what it was 5 years ago. This is a remarkable improvement and is driven by enhanced energy efficiency and increased share of production coming from fields which are powered from shore. This strong performance solidifies our position as a global industry leader in greenhouse gas emissions intensity, consistently demonstrating in the recent quarters. When benchmarked against approximately 300 largest upstream oil and gas companies worldwide, Aker BP stands out as one of the very best on emission intensity, as illustrated on this chart.
Of course, this is a very good position to be in because it gives us an excellent starting point for further reductions. This chart illustrates how we are going to achieve our decarbonization targets, with a goal of reaching net zero Scope 1 and 2 emissions by 2030. A year ago, the electrification of Edvard Grieg and Ivar Aasen resulted in a significant reduction in emissions. Now, approximately 80% of Aker BP's production is powered from shore. In 2023, we have signed up to OGMP 2.0, displaying our commitment to further improve measurement and performance of methane emissions. Moving forward, additional emissions reduction will be realized by gradually phasing out older fossil-fueled assets. The most substantial impact is expected around 2040, when our 2 remaining non-electrified field, Alvheim and Skarv, will be retired.
Furthermore, we will continue working on energy efficiency, which will also contribute significantly. Beginning in 2030, we plan to neutralize all remaining Scope 1 and 2 emissions through reforestation and other carbon removal initiatives, as depicted by the green part bars in this chart. We are actively building a portfolio of these initiatives, and we've already covered for all expected emissions until early 2038. At the end of 2022, we and our partners submitted a total of 10 PDOs to the Norwegian authorities. One project, Troldhaugen, in the Edvard Grieg area, was later withdrawn. This has allowed us to accelerate the startup of Symra into 2026, which is the only change on this list compared to last quarter. The Frigg East discovery from last year has not yet been included here.
We do, however, expect to include it in the Yggdrasil project when we have been through the normal decision gates in the partnership. Now, we really look forward to delivering these great and profitable projects, which in total will unlock some 707 million barrels of oil equivalents with robust economics. Yggdrasil is the largest of these projects, consisting of a dozen discoveries in the area located between Alvheim and Oseberg. This is the next major development in Norway, and through excellent cooperation across licensed partners and the supplier alliances, we open a new and prospective area in the North Sea.
It's the morning of this very day in 2033. This is Yggdrasil. Aker BP produces oil and gas from nine different reservoirs and 55 wells in the area, which extends around 60 km in the North Sea. Three platforms, nine subsea templates, oil and gas export, and power from shore. On this day, in 2033, there's not a single person offshore, not one. Yggdrasil is operated from an integrated operation center in Stavanger. A team of around 15 people work at this center, making sure that Yggdrasil is operated safely and efficiently. The control room in Stavanger is open. This facilitates efficient cooperation with no separation between onshore and offshore teams. This is one team. The control room technicians work closely with the production and process engineers. We have a digital representation of Yggdrasil, a full-fledged operational twin.
Data streams from all parts of Yggdrasil, from reservoirs, wells, and facilities. We monitor the overall facility with real-time integrity, guidance, and control. Empirical data, both our own and from cooperation with suppliers, ensures optimal operation of the facility. We use the data to predict the condition of equipment, also when maintenance is needed. We use the data to simulate production scenarios to optimize production. We have a high degree of sequential control, so we can get the facility up and running quickly in connection with startup. The facility is autonomous. Equipment and wells are tested automatically. In the afternoon, on this same day in 2033, almost everyone in the operation center heads home. Few people are involved in operating the entire Yggdrasil area. This is what we are aiming for, because with Yggdrasil, Aker BP is setting a new standard in offshore operations.
This requires an innovative approach when we design, build, and plan for operations. The area contains a total of more than 700 million barrels of oil equivalent. Together with our partners, Equinor and PGNiG Upstream Norway, we're now able to extract resources that were previously considered not commercially viable.
As you just saw, at Yggdrasil, we are planning to set new standards for field operations. We plan for remote operations, unmanned production platforms, integration of new technology, and implementation of data-driven decisions and work processes. We are also digitalizing the project execution in collaboration with our key suppliers and alliance partners, and the field will be powered from shore to minimize the carbon footprint. Moreover, Yggdrasil will function as a hub for new potential tie-backs in the future. In 2023, this was substantiated by the Fregi discovery in the same area. In the history of the E&P industry, there are plenty of examples of projects that have run into problems that cause delays and cost increases. We aim to avoid falling into that category.
Now, these projects are essential for Aker BP's value creation, and we have therefore invested substantial time and effort into developing a project execution model that drives quality and efficiency. The alliances are a cornerstone in our execution model, and our alliance partners are deeply integrated into the way we work. These partnerships are crucial for securing competence and continuity, internalizing the effects of continuous improvement, and ensuring alignment of goals and incentives. The second principle involves standardization, which is the key to drive down cost and complexity, both in the development phase and during operation. For instance, we will be using the same type of compressor on both Munin, Hugin A, and Valhall PWP, with the same requirement, specification, and synergies in project execution, as well as in operation.
We have also standardized subsidiaries across Yggdrasil and the Skarv satellites, facilitating efficient execution and providing operational flexibility and reducing cost. The third principle is what we call frontloading. Good preparations are the key to successful project execution. This establishes the groundwork for quality during the execution phase and for the final product... When the quality is right, we typically also minimize deviations on costs and schedule. Now, this is why we always involve our suppliers at an early stage in every project. We collaborate early with the suppliers on critical input factors to facilitate efficient engineering, mitigate late changes, and uncover interdependency between project plans to optimize the overall execution. We also spend considerable time with our alliance partners to understand the market, secure capacity, and develop sourcing strategies.
The activity level in our project has now really gained momentum, and here you can see a collection of images from some of the construction sites. At the Aker Solutions yard in Verdal, Norway, it currently stands out as one of the more bustling sites. Here we are constructing jackets for both the main Yggdrasil platform, that's the Hugin A, and the Valhall PWP. These are substantial steel constructions measuring 150 meters and 107 meters respectively, and consisting of roughly 30,000 tons of steel. Now, simultaneously, we are making substantial progress in manufacturing the Yggdrasil subsea template in Estonia, and the Hugin A living quarters are taking shape at Stord in Norway. Additionally, construction has commenced on various modules across different locations in Norway, Scotland, Poland, and Thailand.
Civil construction work and power line installations for Yggdrasil power from shore are also well underway. In summary, our projects are advancing well. All main contracts have been placed, securing the necessary capacity for all main delivery, and construction activities are proceeding according to plan. In the initial CapEx estimates for the PDOs, we meticulously considered and factored in inflationary pressure within the supply chain, and we incorporated these assumptions into the CapEx estimates. While we have observed cost variations in some components, that is, some increasing, others decreasing, overall, our estimates have proven to be quite accurate, and our CapEx projections remain stable. To reiterate, we are confidently on track to deliver the project with regards to both time, cost, and quality. The project will contribute significantly to Aker BP's future production, which is projected to reach around 525,000 barrels in 2028.
Aker BP is investing around $20 billion before tax in total in these projects. We calculate an average break-even oil price of $35-$40 per barrel. To further illustrate the attractiveness of this project, we estimate an average payback time of 1-2 years at an oil price of $65 per barrel for the total project portfolio. Even with a significant focus on our major investment program, we must also keep an eye on longer term growth opportunities. E&P is a long-term business, demanding a continuous focus on adding resources to backfill the resource base. There are essentially, of course, 3 ways to build a resource base: exploration, increased recovery, and acquisitions, and we are actively pursuing all these avenues. M&A transactions have played a pivotal role in Aker BP's history.
The Marathon, BP, and London transactions have collectively been transformative, shaping Aker BP into the company we are today. We continue to view M&A as a vital tool for the company's ongoing development. However, few things can rival the value creation from successful exploration. And today, I'm joined by Per Øyvind Seljebotn, who will provide further insights into our work and ambitions on this crucial field. Please, Per Øyvind.
Thank you very much, Karl. It's a pleasure to be here to talk about the next wave of profitable growth. Aker BP remains true to its exploration strategy, following multiple successful exploration years. We plan to remain actively involved in exploration on the NCS through our significant acreage position. Currently, we are the second-largest holder, with over 200 licenses on the NCS, and we are the operator for 70% of these. In the recent APA awards, we were awarded 27 new licenses, reaffirming our commitment. Going forward, we aim to continue solidifying our acreage position through licensing rounds and transactions. We want to be the best explorer around our existing facilities, and around 80% of our activities are within infrastructure-led exploration, targeting discoveries with high value, short lead time, and low CapEx.
Such discoveries have positive synergies with existing assets, both in terms of cost and asset life. The remaining 20% will target high risk, high reward wells in new areas. We will also aim to keep a stable program size of around 10-15 wells per year. Two years ago, we set an ambitious exploration target of adding 250 million barrels net to Aker BP over five years, up to 2027. In 2022 and 2023, we have taken large steps towards that goal. In 11 discoveries, we have added more than 150 million barrels net to Aker BP. However, as the nature of exploration is inherently uncertain, we will not relax our efforts. One of the key success factors is applying new technology. Take a look at this.
Exploration on the NCS is a data and knowledge-driven creative process, leveraging decades of data acquisition, interpretation, drilling results, and subsurface understanding. We at Aker BP need to be better than our competition at using all this information. Our Exploration Robot uses AI to automatically interpret huge amounts of well data, analyze it, and link it to seismic data. The Exploration Robot helps us find, mature, and risk new exploration targets using empirical evidence, and it's actively used in strategically important areas like Yggdrasil.
At Aker BP, we believe that AI gives us a clear competitive advantage in exploration, and that is why we have built an industry-leading team of subsurface data scientists that work integrated and side by side with the explorationists. Our guiding principle is to use computers for what computers are good at, which is finding patterns in large, multidimensional data sets. In practice, that means that we have used machine learning and generative AI to help consistently interpret subsurface data, flag and screen for new exploration leads and prospects, and find data-driven second opinions in risking and portfolio activities.
As an example, we have put large language models, as seen in ChatGPT, on top of decades of internal geoscience documents and data. This gives explorationists a co-pilot to mine relevant information, find analogs, counter examples, calibrate prospect risking using empirical evidence, and more.
For us at Aker BP, AI is not an alternative to exploration work, it is a force multiplier. Subsurface data science, in combination with traditional exploration work, helps free up human experts to focus on the difficult problems. The name of the game is better data-driven decisions, more prospects, which in turn means more barrels at lower cost. In 2023, the Exploration Robot supported us in identifying and de-risking opportunities in the APA application. In 2024, our goal is that it will identify a prospect as well as right parts of the application. We are convinced that digital technologies will help us drive value creation and exploration. The same technologies will also help us increase value in our producing assets. We are investing in several new technologies that can improve our exploration success and enhance recovery from our fields.
One example that has had a significant impact on our ability to understand the subsurface is ocean bottom node seismic. The processing technology has now caught up with the potential in this data, and this gives us superior imaging of the sub area, as well as optimizing the field development. We are now working to see how we can collaborate with the seismic industry to apply this technology to larger parts of our core areas. So watch this space. The pace of development and the value applying new technology has not been higher since I joined the industry about 25 years ago, and I'm very excited to see how much value this can create in the next few years. So now let me briefly review our exploration performance in 2023. 2023 was indeed another year of successful exploration for Aker BP.
The main discovery was Frigg East, with around 40-50 million barrels net to Aker BP. This discovery increases the Yggdrasil resource base with 10%, and with relatively low additional investments, it will increase the value even more. Currently, the discovery is being matured towards concept selection. The Frigg East discovery was done by two pilot wells and two long horizontal wells. The team utilized state-of-the-art production well drilling technologies to perform a safe and excellent drilling operation, and collected a huge amount of data about the reservoir in Norway's longest exploration well to date. Through the year, we discovered more than 60 million barrels net to Aker BP at a cost below $1/barrel after tax. Together with the discoveries we made in 2022, we are two-thirds on the way towards our 2027 resource target of 250 million barrels.
Today, I'm very excited to present our exploration program for 2024, built around the same strategy as before. The 2024 program consists of 16 wells. Thirteen of these are targeting near-field opportunities, while three wells are in the high-risk, high-reward category. The near-field opportunities are spread across different areas and geological play types. A couple of wells to watch are the high-risk, high-reward wells, Kallfjell and Alvheim, deep with high potential in mature areas of the NCS. Storjo Vest is a follow-up to one of our 2022 discoveries, and can help firm up the next subsea tieback developments to Skarv after the ongoing Skarv Satellite project. Five of these wells have been moved from 2023 to 2024 due to rig schedule changes. Two of these, Ferdinand and Hassel, are in the Wisting area, targeting new volumes that can improve the commerciality of Wisting.
In combination with a further maturation of the development concept, this could pave the way for a commercial development or visiting a few years down the road. The Rondeslottet well that was canceled in 2023 due to technical challenges has now been postponed to early 2025. Like last year, timing wells can change based on rig performance and rig schedule optimizations. The fact that we are once again delivering an exploration program of this quality tells me that with the right technology and competence, exploration on the NCS is attractive. Finding new barrels and increasing the production at our hubs is not only done through exploration. We work very hard to unlock further reserves in all our producing fields. New barrels are added both through technology development, active reservoir management, and improved drilling performance.
Some of our assets have significant upside potential that could be unlocked if we were, we are successful in finding the correct training strategy and concept. Examples of this include the chalk reservoirs at Valhall and basement formations at Utsira High. This chart illustrates the upside potential in and around our existing assets. The 2C resources of around 800 million barrels represent discoveries that are yet to be developed. 3P reserves of 550 million barrels indicate upside to the current estimated production profiles. Additionally, we have identified an exploration potential of around 1 billion barrels, net risked around existing infrastructure. In total, we see an upside potential of more than 2 billion barrels in our current portfolio.
Today, I will cover two main topics. I will start with a brief discussion of our fourth quarter financials, and I will then move on, move on to our capital allocation plan for the coming years, including specific guidance for 2024. But before I do that, let me start by summarizing 2023 from my perspective, using a few key numbers. Last year was another year with strong underlying cash flow generation. Operating cash flow was $20.4 per share, or roughly $13 billion in total. The main drivers were 168.3 million barrels of oil equivalents, sold at an average price of almost $81, at a production cost of $6.2 per barrel. We then paid $11.8 per share in taxes.
But given that the first three tax installments were for the fiscal year 2022, a year with significantly higher hydrocarbon prices, around $2.1 per share, or $1.3 billion can be attributed to this phasing effect. Consequently, the actual tax payable for the fiscal year 2023 was around $2.1 per share lower. After investments of roughly $5.5 per share pre-tax, or approximately $1.1 per share after tax, free cash flow was $3.1 per share. Of this, we paid $2.2 per share in dividends, up 10% from the year before, and the rest was used for debt service and fortifying the balance sheet.
We increased our financial capacity with roughly $600 million-$6.8 billion, where around $500 million came from new, longer-dated debt. At the end of 2023, our net interest-bearing debt had been reduced by roughly $100 million year-over-year, and our leverage ratio remained stable at 0.2. I will now move on from looking at 2023 in totality and zoom in on some of the highlights from the fourth quarter results. Starting with sales, revenues were $3.6 billion, slightly up from the previous quarter. Volume-weighted average prices were down by 2%. This was, however, more than compensated by higher volume. The production volume was actually 5,000 barrels per day lower quarter-on-quarter, driven by the unplanned shutdown of Alvheim. However, volume sold increased due to an overlift of 23,000 barrels per day.
Over and underlift is, of course, a zero-sum game in the long run, and the movement in the fourth quarter reflects that we entered the quarter with a relatively large underlift balance, combined with the timing of shipments around year-end. Realized liquids price decreased with 5% to $84 per barrel, as the average Brent price fell and the price differentials were slightly down. However, we still saw a strong market for our crude qualities, with an average differential of $1 per barrel above dated Brent. On natural gas, the average sales price saw a seasonal hike of 22% quarter-on-quarter, in line with the European spot market. From the income statement, you can see that the overlift also impacted the cost of volume sold quarter-on-quarter. However, on a per unit basis, cost per barrel produced is not impacted by this effect.
In the fourth quarter, cost per barrel ended at $6.2 compared to $6 in the previous quarter, and the slight increase was driven by phasing of activities. Production cost for the full year also ended at $6.2, comfortably within our guidance range. Exploration expenses were relatively stable. Total spend was $81 million, but as one successful well was capitalized, the expense ended at $67 million. For the full year, total exploration spend was $363 million, below our guidance of $400 million-$500 million, as several exploration wells shifted into 2024 due to rig schedule optimization. Depreciation was up this quarter, both in absolute terms and per barrel. The change is rather technical, as it is mainly driven by increased value of abandonment provisions due to reduced interest rates used for discounting.
The effects are normally quite small, but since Ula, which will be shut down in 2028, carries zero book value, any adjustments to such estimates are immediately reflected in the income statement as depreciation. As should be expected in a quarter with declining oil prices, we also had a non-cash impairment charge of technical goodwill in the quarter. In total, this amounted to $415 million related to the Edvard Grieg and Valhall fields. If you're not familiar with the concept of technical goodwill, we have made a short video on our investor web pages that might be helpful. Since technical goodwill has no deferred tax attached, the impairment flows directly through to the net profit. This result in an effective tax rate in the income statement of 92%, even if the actual tax rate remains at 78%.
Our operating cash flow before tax increased to $3.7 billion, up from around $3 billion in the third quarter. Part of the increase can be explained by changes in working capital, with one driver being management of short-term receivables, given the relative size and timing of overlifts. We also had an uptick in current liabilities as investments ramped up and some positive currency effects. We paid two regular tax installments in the fourth quarter, as we do each year, and we also chose to make an additional payment in October. This is actually great, as the reason is that profits for the second half of the year turned out higher than expected when we set the regular tax installments in June due to higher than expected commodity prices.
Cash flow to investments increased to $1 billion this quarter, in line with the ramping up of fabrication and construction activities across our project portfolio. Our free cash flow for the quarter reached close to $500 million, which is a strong result in a quarter with double tax payments. With that, I will now close off the fourth quarter review and move on to capital allocation. When it comes to allocation priorities, we are sticking to our strategy. The first priority is financial capacity. We are in an industry that is capital-intensive and where the prices of our products are volatile. To be able to thrive through the cycles, a robust balance sheet and access to capital is critical. Our second priority is to fund our investments to deliver profitable growth.
Investing in robust projects with low breakevens is how we in the E&P business create shareholder value over time. The third priority, and to a large extent, the purpose of it all, is, of course, to return the value created. I will now take a closer look at the updated outlook for each of these priorities in turn. Building financial capacity and securing access to capital is a continuous process. Last year, we executed several transactions in the bond market by issuing new long-term debt and repurchasing short-term maturities. Not only did this increase our financial capacity by $500 million, but it also extended the term of our bond portfolio and pushed most of our maturities to after the production startup of our ongoing field development projects.
In addition to this, we secured an extension of our undrawn bank facilities by two more years to November 2028, with options to extend further into 2030. Combined with the strong performance of the business in 2023, these activities provide us with a great position at the start of 2024. With $6.8 billion in available liquidity, a net debt of only $2.4 billion, and a conservative leverage ratio of only 0.2, way below 1.5, which we refer to as the level we would not like to exceed for extended periods. The robust balance sheet is also reflected in our stable investment-grade credit ratings, which is important to access future funding. In sum, our financial capacity and flexibility remains strong, and I believe we are very well positioned for the years ahead.
A year ago, we embarked on the execution phase of a portfolio of development projects with the goal of not only arresting decline, but growing our production to above 525,000 barrels per day by 2028. Since then, we have been progressing the projects as planned, and the main financial indicators of the portfolio remain intact. We still see an average break-even oil price of $35-$40 per barrel, using a 10% discount rate. The average unlevered IRR is around 25% at $65 Brent, and the average payback time from first oil is between 1-2 years. When it comes to the corresponding investments needed to capture these strong returns, the totality is in line with our initial estimates when we took the investment decisions and what we presented to the market one year ago.
Total estimated investments from 2024 to 2028 remains at approximately $20 billion pre-tax. Around 85% is related to projects sanctioned in 2022 and covered by the Norwegian temporary tax regime. The rest is CapEx related to new wells and capacity improvements at our producing assets. On a detailed level, there are of course, moving parts, but in aggregate, the only visible change is a slight modification to the phasing. We have chosen to illustrate the CapEx program graphically with a bit of shading, to highlight the points that the phasing between the years are and will continue to be somewhat uncertain. One concrete example driving this is milestone payments on targeted deliveries around year ends. The Norwegian tax system is among the most stable in the world and has some important features which makes it attractive to invest in profitable growth.
One of these features is the immediate deduction of CapEx from the special petroleum tax. This is very important to understand when considering our CapEx numbers, because from a free cash flow perspective, Aker BP's net after-tax exposure of this CapEx program is just above $3 billion. Even though the Norwegian tax system is not overly complicated, we understand that it takes time and effort to get it right. Therefore, our award-winning IR team has made a spreadsheet model available for download on our investor webpage. The simplified model can be used to estimate both the tax payments and the tax expenses reflected in the income statement. These two are not the same as illustrated with this example. Another interesting feature of the system is that from 2020, petroleum tax losses are no longer carried forward, but instead refunded the following year.
This provides additional balance sheet robustness in years with low commodity prices. I would like to emphasize that the figures on this slide should not be used as company guidance. This is a calculation done with a simplified tax model, with a set of general assumptions for illustrative purposes. As mentioned, the model is available for download on our webpage. Let's now have a quick look at our actual cash tax guidance for 2024. By year-end 2023, we had paid roughly half of the tax for the fiscal year 2023. The rest will be paid in 3 installments during the first half of 2024, in line with normal procedure. For the second half of 2024, the tax payments will be decided around mid-year, and these will be based on an updated full year estimate.
In this chart, we illustrate what these payments might be in different oil price scenarios. One key takeaway is that with stable oil prices, we will be paying less in taxes in the second half of the year, and the reason is the step up in CapEx from 2023 to 2024, which leads to corresponding higher tax deductions. Now, let me summarize the capital allocation plan, including distributions for the coming year, with one of my all-time favorite slides. Although this is one of my favorites and many of you have seen it before, let me quickly walk you through it. This is a summary of Aker BP's value creation plan from 2023 to 2028. The left bar represents the accumulated cash flow from our operations for the period after tax at different oil prices, where 2023 is now included, as reported today.
The second bar represents the uses of cash. The investments, including all planned exploration and abandonment spend, are shown in black on an after-tax basis. The pink bar then represents the considerable cash flow, which is available for debt service and dividends. When it comes to dividends, a key principle for Aker BP is that they shall be resilient and reflect the financial capacity through the cycle, considering our financial outlook and credit profile. Our ambition of growing the dividend by at least 5% per year over the coming investment cycle remains firm. Given the strong results in 2023, the progress on our project portfolio and the future outlook of the company, the board of directors has, for 2024, proposed a dividend of $2.4 per share. This is up $0.2 or 9% from 2023.
In addition to the proposed dividends, the guidance on other key metrics for 2024 is as follows. On production, the exit rate from last year has given us a strong start. We do, however, expect to see normal decline, and we're planning for slowdowns in connection with planned maintenance in the second half of the year, in addition to a maintenance stop currently ongoing at the Sverdrup phase 2 facilities. Johan Sverdrup is producing well above its nameplate capacity, and the operator expects to be able to keep the current elevated production level until late 2024 or early 2025. Considering all these elements, we have arrived at a production guidance for 2024 at 410,000-440,000 barrels per day, where the biggest swinging factor in the forecast is Johan Sverdrup.
For production costs, we expect cost per barrel to remain close to our long-term target of $7. The increase from 2023 is mainly driven by production, as total costs are expected relatively flat year-over-year. On CapEx, we plan to spend around $5 billion as we continue to ramp up activity in our projects through the year and into 2025. As already commented on, the phasing of the CapEx between years is always a bit uncertain, and we are now in a phase where we likely would be happy to see spending a bit more than planned, as this typically could mean that we are accelerating progress. For OpEx, we're planning to spend around $500 million. This is impacted by phasing of some of the 2023 wells into 2024.
The spend covers now 16 wells, seismic and data processing, and field evaluation spend to keep maturing both the Wisting project and the next wave of profitable tiebacks to our producing fields. Lastly, we expect to spend roughly $250 million on abandonment. Most of this is related to the old Hod platform and wells in the Valhall area. And with that, I conclude my part of the presentation, and I will, as always, leave the word back to you, Karl, for some concluding remarks before the Q&A. Thank you.
Thank you, David. And before we open for Q&A, let me just, as I usually do, briefly summarize today key messages. In 2023, we successfully achieved all operational and financial targets, while further reducing our emissions intensity from an already industry-leading level. The field development projects are progressing as planned, on schedule, and within budget. We reaffirm the OpEx estimates and plan to produce around 525,000 barrels per day in 2028. We also delivered strong exploration results in 2023, in particular with the Frigg East discovery in the Yggdrasil area, and we have an ambitious program in place for 2024. The robust cash flow in 2023 allowed us to fortify our balance sheet, and we are increasing our dividend for 2024 by 9% to $2.4 per share.
We will now take a short break before opening the Q&A session. If you wish to participate, please join with the Teams link provided on the webpage, and if you prefer to listen only, please stay tuned, and we will resume in one minute. Okay, guys, welcome back from a relatively short break. I hope you got a chance to do whatever you needed to do. And as usual, we'll now do a Q&A. And also, as usual, Kjetil will run the Q&A. So with no further ado, I just hand over to you, Kjetil.
Thank you, Karl. First question today comes from Teodor Sveen-Nilsen , from SpareBank 1 Markets. Please go ahead, Teodor.
Thank you, Kalle, and thank you for a very comprehensive and good presentation. A few questions from me. Just on Sverdrup Phase three, you briefly mentioned that, just wonder, what's the status there in terms of the bottlenecking? If you could give some data on timing roles, that would be useful. Second question is on dividends. And of course, you have a very strong dividend commitment going forward. I just wonder, how is the willingness to fund the dividend with debt going forward? Now, of course, CapEx will go up, and in a scenario with lower oil price, will you be willing to use your credit facilities to pay dividends? And if so, to what extent?
And then third and last question, that is on production guidance for 2024. Just wonder how much contingency have you baked into the 410-440 thousand barrels per day guidance? Thanks.
Thank you, Teodor. Actually, David is also running non-op in Aker BP, so maybe you'd like to point that out. So maybe you'd like to answer the unsettled question first?
Yeah. Yeah, no, I can definitely do that. Thank you, Karl. On Johan Sverdrup Phase Three, of course, this is work ongoing, subsea development. I think Equinor yesterday talked about 2028 as a potential date for Johan Sverdrup Phase Three coming on stream, but this is a continuous development. And what this is about? It's about adding new wells and adding new well slots. So phase three is continuous work over the next few years in order to make sure that we keep production as high as possible over the next few years.
You're gonna do that one, too?
I'll do all the questions. Okay, good.
No, no, I can take the last one on production guidance.
Okay, perfect. Yeah, with regards to dividends, so of course, when we look at underlying cash flow generation in the company, it's very strong. And as I showed in the presentation, when you look at the capacity over the next few years, depending on oil price, it's quite significant. In any individual years, year, the free cash flow generation will be, of course, impacted by hydrocarbon prices the year before, phasing of taxes, and so on. So when we look at this, we look at this through the cycle. What does that mean in practice? Well, it means that, in any given year, yes, net debt could increase, as a function of the fact that we are investing in profitable growth.
But we are very mindful that the number one priority is to maintain a robust balance sheet and financial flexibility. So the minimum ambition of 5% per year is strong and fortified. And then, this time around, for 2024, we have guided on a 9% increase, in line with policy.
And then your final question on 2024 production guidance. Of course, the production guidance as such, and the balance between the, or the range rather, between 410 and 440 is, it's basically an assessment of uncertainty, and we run an uncertainty analysis based on a technology called or a technique called Monte Carlo. But one way of conceptually thinking about this, is that we assumed previously that we would be able to maintain the heightened or enlarged rate on Johan Sverdrup well into 2025. Now, the operator has informed us that they might reduce this volume earlier, that is late 2024 or early 2025. And one way of thinking about this is that that uncertainty has now been encapsulated into, the production guidance for 2024.
So that means that there is, yeah, there is quite a bit of uncertainty in that element, but I would say the production guidance is relatively robust. I think that's as far as I'll go on that question.
Okay, thanks. Just a follow-up on the dividend and what you said, David. The way I interpret the downside on the dividend question is, as long as net debt to EBITDA is below 1.5, you will be willing to use your balance sheet if it's required to increase dividends, right?
I think the way to interpret it is that we will make sure that we have a robust balance sheet, and financial flexibility, and leverage ratio will, depending on, of course, oil price, go a bit up and down, but we will definitely maintain it under the thresholds that we target for extended periods. And then I think just worth reiterating the point that I made during my presentation with regards to 2023 free cash flow generation, right? So, the way that I phrased myself in the presentation, we had the free cash flow generation of $3.1 per share in 2023, but in 2023, we paid also taxes for the fiscal year 2022. And that sort of additional payment was around $1.3 billion.
Then if you compare that to the dividends, of course, in 2023, you get a sense for the variances here. So, underlying cash flow generation from a portfolio that's producing over 400,000 barrels per day, with a production cost around $6-$7 per barrel, is of course, extremely strong. And then we look at this on a holistic basis.
Understood. Okay, I'll leave it there. That's all for me. Thanks.
Thanks, Teodore. Let's go on, Kjetil.
All right, the next question is from Oscar Rønnov from Kepler. Please, Oscar, go ahead.
Thank you, Kjetil, and good morning to everyone. I just have a quick question on the recent Oslo district ruling regarding the PDOs and the failure for the Norwegian government to account for all the environmental effects. This results in a postponement of, among other things, your dredging and building of gas pipe in relation to the Yggdrasil project. I'm just wondering, in terms of timeline for the project, do you see this having any material effects on the schedules of either Yggdrasil or Tyrving? Thank you.
Thanks, Oscar. Yeah, so firstly, what is this case really about? And you're absolutely right. This is not the case about developing the oil and gas on the Norwegian Continental Shelf. It's whether or not the state has made a procedural error in its assessment of the combustion of hydrocarbons, or so-called Scope 3, when we did the consequence ruling. What's that?
Uh, the-
Consequence assessment, really. You can have your opinions about whether or not what is done is correct. The state has appealed both the main verdict, but also the preliminary injunction. Then your statement that this will cause delay is incorrect. So far, the projects are moving ahead. We have the necessary proposals, or approvals, rather not proposals, to carry out the activities in the next few months. And my assumption is that the appeal on the preliminary injunction will be concluded before this becomes a key issue.
Thank you.
All right, then. The next question comes from Yoann Charenton from Société Générale. Yohan, the floor is yours.
Good morning, everyone. Thank you for this presentation. I will have a few questions. One is related to slides 51 and 50. So thank you, David, for updating this, what you refer to as your favorite diagram on slide 51. I've just looked at it more closely, and I can see that the dotted lines drawn on the left-hand side are moved down, especially for the higher oil price case. Looking at slide 50 as well, which is showing the scheduling for tax installments, you have updated, of course, the tax installments for the first half of 2024, so in relation to last year, and they point basically to higher payments overall versus what was communicated last quarter.
I'm just trying to understand what has changed, and I will appreciate if you could provide any color on the main drivers behind these moves. That will be my first question. The second question is related to Johan Sverdrup in terms of crude grade pricing. We have seen quite some changes in recent months in terms of how Johan Sverdrup differentials have moved, so in relation to Dated Brent. That would be great if you could just provide a short-term outlook for the grades based on your own understanding of how things could move going forward. And then the last question will be in relation to Valhall.
We have seen that you took an impairment in the last quarter, and I'm just wondering if you could provide an update of the share of Valhall in your 2C resources, because last year, I mean, at the end of 2022, Valhall overall accounted for a quarter of your 2C reserves or resources. So I would like, if possible, to get an update on this.
Okay, that's quite comprehensive. I think we'll start with tax and value creation, David.
Yeah, I can definitely do that. So the main change from the sources and uses graph this year, compared to what we illustrated at the Capital Markets Day or Strategy Update last year, is basically that we have incorporated the actuals from 2023. And of course, then with an actual realized hydrocarbon price less than $90, when you incorporate that into the graph, that of course means that some of the lines moves slightly. And then, of course, the updated production profiles, CapEx facing all the nitty-gritties, goes into the updated simulation. And I'm sure that when you start looking at it really, really closely and measuring the lines, you will see that there are only very minor adjustments linked to this. So no material changes.
The main change is that we have included 2023 as reported today. Second question with regards to Sverdrup crude differentials. I'll do that?
Yeah, please go ahead.
Yeah. So, when we look at Sverdrup crude, crude differentials, and you can, of course, also observe this, as you mentioned, on Platts, the differentials are varying over time, but typically varying with a couple of $ per barrel, ±, around dated Brent. And this is sort of natural variations with regards to supply and demand for that specific crude quality, and also to what extent crude, the crude also is exported east versus Europe. I will not give you a short-term estimate or a forecast of where we see that differential go over the next few months.
Of course, that's also commercially sensitive, but we expect Sverdrup, based on the feedback that we're getting, to have a high demand also in the months ahead.
And maybe the only addition, Johan, is that, and you might know this already, is that we have seen recently some shipments of Sverdrup going to Asia, which again, opened the arbitrage that's been closed for quite a while. So that's, of course, a positive indicator for the crude differential. And then your question on Valhall and the impairment case. Valhall is not impaired in this quarter, and I don't think there are any changes to the 2C reserves or resources on Valhall in this quarter either.
I can, I can qualify that. So, so there's impairment of technical goodwill on, on Valhall this quarter together with Edvard Grieg and Ivar Aasen, which is, of course, is a bit, specific, but it's not impairment of, of resources.
Mm-hmm.
So this is, of course, driven, as you know, and most of you on the line know, by previous acquisitions and the way that we have to account for the differences in accounting and tax. So that's to be expected over time, specifically in quarters when the forward curve for oil and gas prices drops and as you are producing out, call it, volumes in the asset.
Thank you. Have a nice day, then.
Thank you. Let's move on, Kjetil.
Yes, absolutely. It's from John Olaisen, from ABG. Please, John, go ahead.
Yeah, thank you for taking my question, and good morning, everybody. I can see from the fact pages from the Norwegian Petroleum Directorate that the water production is increasing significantly at the Johan Sverdrup field. So I just wonder if the water production is higher than expected. And also, I had hoped for the coming off of the plateau to take place a little bit later than 2024. But if you could elaborate a little bit about that. Do you have sufficient water handling capacity on the topsides, et cetera? And is there anything you could do to increase the water handling capacity and thereby extending plateau?
And then also, maybe if you could elaborate a little bit on what kind of depletion rates we should expect from Johan Sverdrup once it goes off plateau, and what can be done to fight that, apart from, of course, the Phase 3? Thank you.
Good. Excellent question. Yes, you are right. We are seeing water in some wells in Johan Sverdrup. The behavior is really related to well-by-well coning, and it's not an overall well. It's not an overall field water cut development, it's a well issue. We are in the course of 2024 putting another 8 wells on stream on Johan Sverdrup, which will limit the issue as it's directly correlated and linked to well rates. And of course, the total field rates are capped to the water handling and oil handling capacity. Oil handling, of course, standing at 755,000 barrels of oil equivalents. So I think the main issue here is to get more wells on stream, and therefore, more or less production per well.
And then, of course, the water handling capacity is, at the moment, significant, and quite in line with what we expected, and sufficient for treating the water. And then, of course, the last issue will be mass balance in the reservoir, and we're just doing a turnaround to change out the water injection pump, which are now basically done, I think, to make sure that there is sufficient capacity. So those are the three main initiatives that is ongoing in 2024 to extend the plateau.
And then, of course, the next line of things will be new wells, and this is, as with all, you know, as with all oil and gas fields, as you reach the end of plateau, the way to extend plateau is to increase capacity, particularly water treatment capacity and gas treatment capacity, and add IOR wells. I mean, this is bread and butter for the oil and gas industry. This is what we do in oil fields.
And then on depletion rates, once it goes off plateau, please.
Yeah, that's I don't think I'll guide on that, Jon, at this point in time. The reason is that, yeah, of course, from a technical perspective, you will see the largest depletion rates, relatively speaking, in the first few months after you go off plateau. But that will depend on water volume, on the increase in water volume, well stock, et cetera, et cetera. So that's a pretty difficult assessment to make at this point in time.
But the potential plateau in the second half of 2024, is that what you had expected and what you are already have in your charts, showing the expected production profile for Aker BP in the years to come, or is it a little bit earlier?
I would say that this, as you know, we increased the plateau level quite significantly above nameplate capacity in 2023.
Mm.
And it's been producing extremely well at this level, with nearly 100% uptime, low cost, highly energy efficient. One year ago, I would say we expected it to continue that well, well into 2025, and the operator has now basically said that they assume that this level can be sustained, that's probably a good word, until late 2024 or early 2025. And it's the uncertainty in that timing that is basically incorporated into the guidance of 2024. And of course, that means that the... Yeah, maybe starting another, but that, that means that we, when we assessed this earlier, we had an assumption that it'll carry well into 2025.
That, of course, means that the guidance for 2024 is a bit lower than we assumed a year ago, but it also means that the next couple of years will be impacted by this, call it a little bit more conservative phasing of production. But it's important to note that there are no reserve changes. This is essentially a phasing of production related to the production strategy at the field.
Mm, mm. Sure. Okay, and my second and last question is just an observation on the unit production guidance, production cost guidance for 2024 of $7. It's slightly up from 2023. I wonder if you could elaborate what makes that increase in the production cost, please?
I'll do that this time, David, huh?
That's good.
That's good.
That's good.
So, this is actually quite easy. So the way to think about this is that the underlying cost is essentially stable. We have a bit more activity in 2024 than we had in 2023, so the increase in productivity is taken as an increase in activity. But then, of course, the production we guide for in 2024 is a little bit lower than in 2023, and the difference is the change from 6.2 to roughly 7.
Thank you. That was easy to understand. Thank you very much. That's all from me. Thank you.
All right, then the next question comes from James Carmichael from Berenberg. James, please go ahead.
Hi, morning, guys. Just to follow up on Sverdrup again, I mean, if there's a specific reason for that plateau coming back from 2025 into 2024. It doesn't sound like water cut's the issue, but just wondering if there is something that's changed there to bring that forward versus what you were previously expecting. Secondly, just on CapEx phasing, I guess there's a fairly big step up in CapEx this year, so interested to understand how we should think about that being phased through 2024. And then lastly is just on the carbon storage licenses. I think you mentioned there's a drill or drop decision on one of those coming up.
I'm just wondering if you could give a bit of color on how that sort of drill or drop decision differs from a conventional sort of exploration drill or drop decision, obviously, the commercials, the economics, you know, supply of CO2, et cetera, is all a bit uncertain at this stage. So just a bit of color around that, I think, would be helpful. Thanks.
So, let's start with you, Johan Sverdrup . But as I stated in my answer to John, this is basically a production strategy issue. It's about distribution of volume, and it's about extraction rates, essentially. So that's basically where we are today. I don't think I... Of course, there's a technical discussion to be had on well-by-well extraction rate and coning rates and stuff like this, but you can think about this as production strategy, really. On CapEx facing, David?
Yeah. Also, so CapEx overall is in line with what we had expected. This year, we're guiding roughly $5 billion, and then we are also, as illustrated on one of the slides in the presentation, expecting to increase that next year. And the way to look at, sort of think about phasing through the year, is that we will slowly continue to ramp up towards that level that we will then then have in 2025. But then, it's worth also noting, as I did in my presentation, that phasing around year-end is always a bit difficult. It could be linked to milestone payments, or, you know, linked to specific deliverables, and so on.
The important thing here for us is that we keep progressing the projects according to plan, and then, you know, phasing between the years, and in particular around year-end is less important.
Yeah. And then in reality, and this might not be what the CFO wants to hear, but in reality, I'd rather spend a little bit more than a little bit less in 2024, because that basically will mean that the projects are progressing more rapidly, and therefore milestone payments are coming earlier than we assumed. So it's almost an inverse when it comes to project execution. Now, as we move on to CCS, yeah, well, let me try to frame that discussion. So first and foremost, Aker BP is a pure-play oil and gas company, a proud pure-play oil and gas company. We're much more exposed to oil than we are to gas. In 2023, this ratio was about 86%-14%, and we consider CCS more as an option.
We are uncertain of what the value will be in that value chain, we are uncertain of what the markets will be like, et cetera, et cetera, but we are considering it as a low-cost option at the moment. And that is the framework we'll also go into a drill and drop this decision on. I have no intention of making a drill decision if I don't understand the economics, if I don't think that they are compatible with the internal rates in Aker BP, and I don't see that this is a viable economic case. As I said, we are a pure-play oil and gas company. Then this drill and drop decision, basically, from a regulation perspective, falls under the same kind of regulation as a normal, call it exploration well.
That means that you either make a decision to drill, or you will have to hand back the license. That decision will have to be made in 2025, but so far, we are not really consuming a lot of funds on this, and we consider this as an option at the moment.
Thanks very much.
Sure.
All right. The next question is from Sassi Chilukuru of Morgan Stanley. Sassi, please go ahead.
Hey, that you're muted, Sassi.
He's not muted, but then let's move on to the next caller, which is Mark Wilson from Jefferies. Mark, are you ready?
I am ready. Thank you very much. Kjetil, good morning. David, good morning. Yeah, Karl Johnny. A few questions here. First off, you answered before about the timing of the appeal in Oslo is ahead of activities. But the simple follow-on is, so what if the appeal fails? What would be the implication there? That's the first point. Second point, a lot of questions on the production guidance, a lot of discussion about Johan Sverdrup, understand all that. In your split out of production and through 2023, Edvard Grieg, Ivar Aasen has shown quarterly declines. I just wonder if that's a factor in the 2024 guidance, or is there some outages in 4Q that it recovers from? And then the last point, you say you remain focused on M&A.
Does that or is that still within Norway, or is there an international view on such a matter? Thank you.
I think the questions become increasingly easier to answer as you move through from one to three, Mark. When it comes to the first, what if the appeal fails? I feel that's a bit hypothetical to answer. We, of course, have an exact knowledge of when we need approvals, what the consequence of not getting those approvals are, and we've communicated this clearly to the energy ministry on their request. The appeal is sent in. We expect a rapid treatment within a few weeks, I would say, or some weeks. And certainly, before this will have an effect on the projects, and their progress, and how they progress. Then, if this fails, then we'll come back and see what can be done.
But so far, we have valid approvals for the work that is ongoing at the moment. And then, of course, Aker BP is not a party to this verdict. It's between the NGOs and the Norwegian state. Then on Edvard Grieg, yeah, Edvard Grieg came off plateau after a seven-year of plateau. That means that, as you move, the modeling from a plateau-based modeling to a decline-based modeling, there's always some uncertainty in terms of decline rates, water cut developments, gas handling, and gas treatment capacity, et cetera, et cetera. So there is a little bit of a, yeah, a little bit of a downward revision towards the assessment we had a couple of years ago on Edvard Grieg, but it's not material in any way.
And again, we are assessing an infill campaign. I seem to be saying this a lot these days on Edvard Grieg in 2025. And again, this is bread and butter from an oil and gas industry perspective. This is what we do with every field that comes off decline. This is what we've done with Alvheim, and this is what we do with Edvard Grieg. On M&A, you should assume that Aker BP is a pure play oil and gas company focused solely on Norway.
It's all very clear. Thank you very much. I'll hand it over.
The next question today is from Victoria McCulloch from RBC. The floor is yours, Victoria.
Morning. Thanks very much, all. Apologies if I've missed your answer to these, but hopefully very small, straightforward questions. In terms of timing for Hanz, where should we think about that coming in, at the start of this year, for first production? And secondly, you talk about the variability in the $5 billion of CapEx. You know, how variable could that potentially be, onto the upward side? So how much could we see that increase, potentially if projects are moving ahead this year? Thanks very much.
Yeah, I'll take Hanz first. So in Hanz, we have completed the producer. We are, at the moment, completing the water injector. The well can be put—or the field can be put on stream without that water injector, but we'd prefer to complete it the way it is. And then that will depend—The exact timing will depend on when we have access to diving vessel. That's an ongoing discussion with the vessel owner at the moment. So far, I hope that we'll be able to put Hanz on stream within the first quarter, but, given the weather we've had in the Norwegian Continental Shelf lately, there might be some postponement related to weather. CapEx variation, David?
Yes. Well, our best estimate is $5 billion. And probably not, our team is not going to be happy for me to give sort of a range around that, but my mental model would be, you know, to be honest, ±5%. And then, of course, the best estimate, as always, is what we guide on. And then the milestone payments and the phasing will, of course, move according to the progress in the project.
Super. Thanks very much.
Thank you, Victoria. And now we have, looks like we have Sasi back on the line, Sasi Shilukuru from Morgan Stanley. So if you have a question, Sasi, please go ahead.
You there, Sasi?
You are muted, Sasi. Seems to work. So look, you can try to sort it out. We'll go to the next caller, which is Matt Smith from Bank of America. Matt, are you there?
Yes. Hopefully, you can hear me over the audio. Good morning, guys. Thanks for the presentation. As ever, very detailed and much appreciated. Question really on project execution. I guess, you know, since your cost estimate updates a year ago, all the subsequent updates have been very reassuring, in terms of, execution and progress on those projects. So I guess I just really wanted to pick up on, you know, where do you see the biggest risks to delivering those projects? I guess, sort of, on time, I guess on budget is also a question, but I think timeline is probably the bigger uncertainty. You know, the supply chains are particularly tight. It's probably more difficult to execute these projects at this time than in the past.
So I just wanted to frame from your perspective, sort of where you see the particular pinch points, if you could. And then just related to that, I just wondered whether you are considering disposals at all, as part of that broader M&A strategy, as part of managing that project execution risk, please.
Okay, project execution risk. I mean, this is a very interesting discussion and something that we and I spend—I would say I spend probably 80% of my time on the projects at this moment. And this might sound cocky, but I don't really mean it that way. I think the bit what keeps me awake at night is actually the predictability around shipment routes, ability to source and assess raw materials, and the geopolitical situation. Of course, we have established a strategy where a lot of these projects are prefabricated at yards around Poland, Thailand, Dubai, et cetera, et cetera. That means that there are quite significant amounts of shipment of goods to these yards, and then preassembled units back to the main assembly yards in Norway.
And that means that as we are contracting heavy lifters or barges or whatever they need, they might need to be shipped on. Changes that because of geopolitical consequences is something we're actually spending quite a lot of time on to get more robust these days. So that's actually, if I were to point out the one risk, that's probably the one we're spending the most time on at the moment. And then, your questions around disposals. You should never rule it out, but in reality, we, we like these projects, we like these fields. We like to be exposed with a high, a high rate and a high percentage in the fields that we operate. So it's not something that is immediately on top of our agenda, no.
Understood. Well, thanks very much, guys.
All right. Now, I believe we have Sasi back on audio line. So Sasi, can you hear us?
Hi, I can hear you. Can you hear me?
Yes, we do.
Ah, fantastic. Good to hear you, Sasi.
Third time lucky, I suppose. No, I wanted to actually check up on the production guidance. Of course, it's been discussed quite a lot, but I wanted to make sure that I didn't miss much on the other part. It seems the 2024 guidance seems to have come down from what it seemed to be around 450 previously. I was just wondering what projects are kind of leading to this decline specifically, and what confidence can we place on the future volumes given that there seems to be a bit of a decline in 2024 rather than previous guide expectations?
I've answered this two times now. Do you wanna have a go at it, David? Maybe you can be clear.
Yeah. No, I think we covered it quite a bit, Sasi, already. So I think the guidance range that we have laid out today illustrates all the range of uncertainty, and particularly with regards to how long we will be able to keep the current sort of enlarged plateau rate on Johan Sverdrup. So Equinor has stated that they expect to keep it at least until late 2024 or early 2025, and that's what's now sort of in the main variation in the guidance range for 2024.
I think with regards to implications for longer term guidance, I think with this update that we now have today, we do have a slightly more conservative phasing of production, in particular on Johan Sverdrup, into the longer term guidance.
Great. Thank you.
Sasi, it was good to finally connect. Now, we have one question left on the list, which comes from Anish Kapadia . Please, Anish, go ahead.
I had a couple of questions related to M&A. You know, it was very impressive presentation in terms of demonstrating your industry leadership around use of technology, use of AI, being ahead of the peers. And what it seems, if I understand this right, is it's helping you in terms of the exploration side of things, but it's also helping you on the development side of things. So I'm just thinking, going forwards, are those gonna be the two key areas in terms of M&A, or do you think that there's still a lot of value to add in terms of buying older existing platforms, or are they kind of too difficult to apply new technology to?
And then my second question, it goes back to one of the earlier questions about expanding internationally. You know, I get the focus on Norway, but again, given this technology leadership, is it not possible to do the same things in mature basins with opportunities such as the UK or the Gulf of Mexico? Or is it the fact that you just don't have the knowledge base, you don't have that data, that means that it's not worth moving into those kind of areas? Thanks.
Excellent questions, Anish. You're actually spot on. So either we've been extremely good in explaining this, which I don't think, or you're quite clever. When it comes to the discussion around technology, I think you're absolutely right. It's actually quite hard to deploy modern technology on, let's say, 20+ year installations. And the reason is not the age itself, it's the underlying systems that retain and transport data on these facilities. They require. They're usually built on spec, they're usually one-off, they're not necessarily industry standards, et cetera, et cetera, and it requires quite a bit of time and money to liberate the data and be able to put modern technology like machine learning, artificial intelligence, GenAI, to work on those platforms. So you're absolutely right. Do that mean that we're not necessarily looking at mid-life or late life?
Well, I think I've been pretty clear that Aker BP is not a late-life company, per se. That is not where we believe that we have a competitive edge. We are running a project at Ula, trying to see what we can—what can be done when you deploy technology, competence, and cost focus on a late life asset. The jury is still out, but the Ula team is very enthusiastic and actually making great improvements... On mid-life change around, I think that's actually still our sweet spot. There are more modern systems. It takes less to liberate data and deploy modern technology, and there are a lot more upsides to be held in terms of drilling infill wells or intervention or these other, I would say, key initiatives or key investments.
It's essentially there where we have the biggest value outtake as well. So in a way, I would say that our technology deployment is focusing on where we have the biggest competitive edge. If you transfer that to M&A, I doubt that you'll see Aker BP going after late life assets. I don't really see that fitting our strategy. Quite the opposite, I see this fitting with the existing strategy we have of field development, exploration, and mid-life asset turnarounds. So you can from that, you can infer that late-life portfolios is not necessarily where we'll focus on an M&A strategy. Then your discussion around technology deployment into continental shelves like UKCS, or GOM, it's not necessarily. Yeah, I think the technology deployment strategy would work as well as it would in Norway.
That's not what it's about. It's not about our knowledge base of subsurface, which I think we are actually pretty capable of, but it's about our focus. It's about this triangle between, understanding regulatory framework, working within an ecosystem that we have established now with the alliances for a number of years, and then being focused on something. And focus is extremely important to a company like Aker BP. We've stayed focused, we've stayed close to our strategies in 2016, and that is the reason I intend to stay focused on the Norwegian Continental Shelf also going forward.
Great. Thank you.
Thank you. There seems to be no further questions, so maybe you would like to wrap it up, Karl?
Yeah, sure. I'll do this short and sweet. So thank you, guys, for listening in. And thank you for all the positive comments. That's highly appreciated. And with that, I'll just close the Q4 presentation and full year 2023. Wish you a good day, and welcome back in a quarter.