Share buyback is an integrated part of our capital distribution. We continue our program from 2021 of annual buybacks of $1.2 billion, but based on our balance sheet and the plans we present today, we will do more in 2024 and 2025. We announce a two-year buyback program of $10 billion to $12 billion in total. For 2024, we continue the buyback level from last year, of $6 billion. In total, this gives a capital distribution to shareholders of $14 billion in 2024, $8 billion to $10 billion in 2025 and increased predictability for the future. I will not repeat all the numbers, but let me sum up: We are positioned for transition and growth. Towards 2035 we can deliver a stronger cash flow from a broader energy mix, with lower emissions. And with strong returns, we continue competitive capital distribution with increased predictability.
So thank you all for the attention. I really look forward to all your questions later. And as Bard said, I’m joined here with a full executive team, and we are happy to answer all the questions. But first, Kjetil, the floor is yours.
Kjetil Hove: Thank you, Anders. The Norwegian continental shelf continues to deliver solid results and we expect to deliver solid production and cash flow all the way to 2035. The picture on the front page you see the Breidablikk field which is tied-back to the Grane platform, and the picture is selected for a reason. We delivered Breidablikk four months ahead of plan and below budget. Demonstrating our project execution skills. In addition, it visualizes what we are doing on the Norwegian continental shelf. Grane was put on stream more than 20 years ago. And according to the initial development plan, the field should have been close to life end by now. Based on consistent investments in Infrastructure Led Exploration and Increased Oil Recovery, the platform is now producing above 100,000 barrels and is expected to be in production until 2060, at least.
Now, we are working on decarbonization that production by electrifying the installation reducing the carbon intensity to below 0.1 kg CO2 per barrel within 2030. This is what we are doing on the Norwegian continental shelf; we are utilizing our infrastructure and capabilities built through the last 50 years, we are maintaining a high production level, and thereby creating a long-term cash flow, while reducing our CO2 emissions. In 2023 we delivered a strong cash flow from the NCS. At the same time, we reduced CO2 emissions from our operations. In 2023 and 2024, our CO2 emissions will be reduced with more than 10% and at the same time we will have a production growth. Towards 2035 we expect to maintain the production level from the NCS at the same level as we started this decade, 1.2 million barrels of oil per day.
This will generate an average annual cash flow from operations after tax of around US$12 billion from 2024 and all the way to 2035. To deliver this, we plan to invest at an average level of around US$6 billion annually towards 2035. These investments will be within four main areas: to deliver on our sanctioned project portfolio, to mature and sanction our large non-sanctioned project portfolio, to increase the recovery from our fields, and to develop discoveries from our extensive infrastructure-led exploration effort. We will also invest in decarbonizing our production reducing our CO2 footprint with 50% in 2030, 70% in 2040 and close to zero in 2050. We have a very robust project portfolio in the execution phase on the NCS. We have 21 projects with an average break-even less than US$35 per barrel and a payback time less than 1.5 years.
The project portfolio will have a CO2 footprint less than 4 kilo CO2 per barrel since most of the projects are tie-backs to installations that are or will be electrified. And this project portfolio will add around 250,000 barrels and give us a production growth toward 2026. In addition to the large sanctioned project portfolio, we have an even larger number of non-sanctioned projects. We have more than 30 projects that we are maturing towards investment decision in the coming years. The projects are in an early maturation phase, but we expect an average break-even of the portfolio of around US$35 per barrel and a pay-back time around 1.5 years. For many of the new sub-sea tie-back fields, we are looking into new ways of working to reduce the maturation and execution time with 50% and the cost level of at least 30%.
This will reduce the break-even for these fields with 30% compared to a more standard sub-sea development. This will be done through new technologies such as the Cap-X subsea wells and by taking out portfolio synergies. These projects will give us around 350,000 barrels in production after 2030 and will therefore be an important contributor for us to maintain the production level after 2030. These projects will have even lower CO2 emissions since they will be tied back to electrified installations. In addition to the large sanctioned and non-sanctioned project portfolio we are working hard to increase the recovery factor from our fields. Historically, we have been since sanctioning being able to increase the average recovery factor from around 30% to around 50% from our oil fields.
There is still a large remaining potential in our fields and we plan to deliver 50 to 70 increased recovery wells annually in this decade. Many of these wells are using new technologies such as retrofit multilateral wells, multistage fracking, and advanced completion solutions reducing the cost and increasing the production. These are highly profitable barrels with break-even of around US$20 per barrel and payback time less than a year. We are also planning for around 300 well interventions annually to increase production from our existing wells. And in addition, for many of our late life assets, we are planning to sanction low pressure projects to reduce the reservoir pressure and thereby increasing the recovery from the fields. This increased recovery effort will give us an annual production of around 150,000 towards 2035 with a very low CO2 footprint.
And finally, we believe there still is an attractive remaining exploration potential on the NCS. These are high value barrels since they can be tied back to existing infrastructure that is already paid for and decarbonized. We are therefore planning to drill 20 to 30 exploration wells on the Norwegian continental self towards 2035. In this decade, we plan to be closer to 30 wells yearly and more than 70% of them will be in licenses that we already hold. The remaining wells will be drilled in licenses from the annual license round. And this year we were awarded 39 new licenses, which is one of the largest awards we have ever had on the Norwegian continental self. Our exploration strategy is that around 80% of the exploration wells will be drilled close to the infrastructure in known exploration plays.
This is normally low risk exploration, with high probability of success. New discoveries can be put on stream quickly since they will require limited new infrastructure. A recent example is the Obelix discoveries last year, that revitalized the deep-water Norwegian Sea close to the Aasta Hansteen field. The remaining 20% of the exploration wells will be drilled in new plays, still quite close to our infrastructure. These are higher potential wells, but with somewhat higher risk than the pure Infrastructure Led Exploration targets. These wells can open new plays also in known areas such as the Kveikje, the Heisenberg and the Norma discoveries during the last years. Discoveries that you may not have heard about, but you should not underestimate them.
Because they are many of them and these could open new plays with large potential on the NCS. The key driver for our view on the potential on the Norwegian continental shelf, is the investments that we have made in new exploration seismic the last five years. This is seismic with “fit for purpose” technologies that reveals potential that we did not see on our legacy seismic and Hege will revert back to this later after me. After 2030 we expect that we will get 100,000 to 300,000 barrels per day from our infrastructure-led exploration effort. And by adding the investments in project, increased recovery and infrastructure-led exploration, we expect to deliver 1.2 million barrels per day in 2035. Our ability to develop and utilize new technology has been a key reason for our value creations on the NCS the last 50 years.
Also, in the next decades, we believe technology will enhance the value creation on the NCS. And we are, therefore, planning to invest US$300 million to US$400 million annually on technology development on the Norwegian continental shelf in the coming years. So Hege, can you please elaborate on the technology efforts that we are doing on the Norwegian continental shelf?
Hege Skryseth: Good afternoon, everyone. It’s a pleasure to be here. We are now rescanning our core areas on the NCS, all over again for remaining resources. A very good example is the Troll area where we have 500 million barrels proven with a significant upside potential. This equals to a full-year of NCS production. We identify opportunities that were not visible to us before. And this were due to: First, over the past two years, we have invested $200 million in new high-quality exploration seismic. With technologies like ocean bottom and top size, both representing a step change in image quality. And this is on top of the 70 petabytes, which is a huge number of legacy seismic and well data that we already have. Second, to significantly increase insights and speed, we have developed AI-based technologies using deep learning algorithms.
These recognized complex patterns in pictures, sound waves and other data sets. What used to take weeks, now take hours. Third, by combining this with the unique confidence that we have on the NCS, we see that mature areas are still very prospective. We are targeting all core areas of the NCS, such as Sleipner and Johan Castberg. For these two alone, we have identified 37 high-quality leads and prospects. To secure competitiveness, both on the NCS and in our international portfolio. We are constantly seeking improvements through technology. This is on safety. It’s on emission reduction. It’s on value generation and it’s on cost. In 2019, we opened our Integrated Operation Centre in Bergen. Here, we are monitoring a huge amount of data from our offshore operations to optimize production and improve decisions.
