Welcome to Fornebuporten and welcome to Aker BP's Capital Markets Day for 2018. We're very pleased to see so many of you here to join us today. Before we start, we'll have a quick HSE brief. The emergency exits for this room can be found on your right-hand side or the main entrance that you entered into this room. We do not have any planned fire drills today, so if the emergency alarm goes off, please evacuate the premises. Please turn off your mobile phones to avoid interruptions. Our goal today is to give you a better understanding of how we work in Aker BP to create the leading independent offshore E&P company. Today's presentation has been divided into five parts. We'll start off with going through our corporate strategy by our CEO, Karl Johnny Hersvik, and then we've divided into our three strategic themes, execute, improve, grow.
Karl will go through execute, then improvement will be presented by Per Harald Kongelf, our SVP on improvement. The growth section will be Karl Johnny Hersvik and Gro Haatvedt, our SVP of exploration. Finally, Alexander Krane, our CFO, will try to tie everything together in our financial section. We'll conduct a Q&A section after each session. There will be a coffee break between the two, before we end our presentations at around 4:00 P.M. this afternoon. With that, I'd like to introduce you to our CEO, Mr. Karl Johnny Hersvik.
Okay. Can you hear me? Are we recording? Good. We should be okay. Usually when I'm here, I'll say good morning, since this is not a quarterly presentation, good day, everybody. It's great to have so many of you here today. As Jonas said, we'll try to run you through the highlights of our business model. Also try to provide some in-depth, concrete examples of where we believe Aker BP has a competitive edge. Also give you a little bit of flair for why we believe that the return to our investors, either in terms of growth of share price or dividend, has been superior to our competitors in the last three years. My hope is that you leave today a bit wiser, a bit smarter, and also with a better understanding for our overall strategy going forward.
2017 has been a year marked by extremely high activity. The Hess acquisition allowed even deeper exposure to the Valhall field, which we'll come back to, but also provided another example of an extremely successful M&A track record originating back all the way to 2014, demonstrating that the success we've had in the M&A market over the last three years has not been a coincidence. We have delivered on our promise to deliver three PDOs to the market, all of them with increased volumes, reduced costs and, to a certain extent, substantially reduced execution time. The 2017 production we guided towards the high end of the range. We ended up at 139,000 barrels excluding Hess, and 160 including Hess. Whereas the high end of the guiding was 140.
We are actually about 6% above the guidance we gave at the previous capital market days in terms of production, if you exclude M&A activity. We've had a fantastic reserve replacement over this year, and this is a concrete example of the Aker BP strategy with very in-depth subsurface work, utilization of the full suite of data available to us, and data acquisition and investment in data where we need to, but also our commitment to reserve utilization in the fields where we are operator. In total, we've added about 2.3 times the production. If you include inorganic growth, we have about the reserve replacement rate of four, which is quite significant if you put that on top of our already growing production profile. The cash flow in 2017 has been high. The dividend coverage is about three times from Q4 2016 to Q3 2017.
We have paid out in that period $250 million. Finally, we are today increasing the dividend to $450 million in 2018, which is up from $350 million announced following the Hess transaction. We're also dedicating our strong ambition to add another $100 million to the dividend payment each year until 2021. For those of you who have a quick head for those kind of calculations, should give us $750 million in 2021. All in all, a year with high activity, but also a very successful year in terms of economic results. Now, I thought it could be interesting to review the investment case, to give a little bit of a flair for why do we believe that it's still prudent to invest in Aker BP.
Our strategic ambitions stand clear and have remained clear, at least for the last couple of years, and that's to create the leading independent offshore E&P company. While the strategic direction has remained clear, as you'll see, we have become even clearer on the activities that underlie those strategic ambition and our dedication and devotion to those activities. The overarching goal is always to increase shareholder value. This, we need to be profitable across the market cycles. We are purely operating on the Norwegian Continental Shelf, which means low political risk and an attractive fiscal regime, which we have proved time and time again by both our investment activity and our M&A activity. We have a strong balance sheet and currently carry more than $2.9 billion in liquidity.
We have a robust investment program, this I'm extremely proud of, where the break even on our decided cases, that is decisions have been made, of $18 per barrel. All in, the break even in the forward program is around $24. If at this point last year, that profile was around mid-$30s. A significant improvement in break even on forward programs. That has resulted in substantial cash generation and growing dividends to the shareholders. We have an extensive improvement programs, and today you'll see concrete results, demonstrable results of that improvement program. I'm actually amazed by the speed of what this improvement program is generating improvements, and how quickly we're able to turn more concepts such as lean into shorter execution time, higher cash generation, and more reserves. We are reorganizing the value chain with strategic partnership and alliances to further capitalize on our lean initiatives.
We aim to be an industry reference for digital project execution. Per Harald will take you through both these subjects in quite a lot of detail. We also believe that we have a strong profile platform for future growth. We're materially oil-weighted. About 80% of our portfolio is liquids, and we carry more than 900 million barrels of reserves in 2P and 2C. In addition, there's a potential to increase to roughly 330,000 barrels of oil production in 2023, which is about a 13% compound growth from where we are today. Finally, we have a proven M&A track record, and we are targeting further selective growth where the key objective is to increase shareholder value, and if possible, increase dividend payment. We still believe that Aker BP is uniquely positioned to take benefit of the current market situation.
Let's leave it at that, I'll go into the strategy and try to give you a few examples of how our overall strategic direction is manifesting itself in concrete actions. Before I start with that, there are some drivers. It's always useful to have an overall macro perspective as a point of departure. We have seen a steady growth in oil demand also in 2017 and 2018, we don't necessarily see a break in that trend in the next few years. There is a lot of volatility in this game. When we say cyclicity is the name of the game, the idea is to be able to handle the downturns and turn downturns into profitable opportunities to increase dividends by improving your business model, reducing cost, and increasing execution time.
Of course, when the tide turns, the benefit doubles or triples or whatever. In total, we have demonstrated our ability from summer of 2014 and all the way out to the end of 2017 to generate value through the cycles. When you have that kind of cyclicity, cost leading is the robust strategy, you'll see that as a predominant topic throughout the presentations today. In addition, you want to have a robust balance sheet and a strong dividend capacity. You need an organization that's entrepreneurial and flexible to cope with challenging market conditions and changes in our strategy. You want to be driven on focused growth, not running after every single opportunity out there. We have chosen to retain a focus on the Norwegian Continental Shelf. We still believe that the NCS is an extremely attractive place to be.
More than half of the yet-to-be-discovered resources are still out there, they are growing as new areas hopefully are opened and more resources are to be utilized. We also see that in an age where carbon emission is challenged, the Norwegian Continental Shelf is significantly lower than the average in the global, Aker BP is lower than the Norwegian Continental Shelf average. Again, I think we can conclude that we are well-positioned to benefit from the Norwegian Continental Shelf attractiveness. This is a slide that we've used repeatedly now to provide a picture of the key components in our strategy. I'll use it as a backdrop when I'm running through my presentation today. In the middle here, you will see maximize shareholder value, I'll demonstrate that that's exactly what we have done over the last three years. On top, you'll see safety.
Always prioritizing safety and quality in our operations, in everything we do, even if we grow significantly in our activity program. We have defined as a primary goal to be cost and capital leading as an offshore independent E&P company. We believe this to be a robust strategy, both against cyclicity but also against other changes in macros. Alexander will take you through the balance sheet. As most of you know, we have reduced leverage significantly in the last couple of years. We have an entrepreneurial and a flexible organization that allows us to scale up and scale down, but also to [capture] new business models and new opportunities quickly and with quality. We are still in a growth mode, both organically and inorganically, as will be demonstrated when we talk about the exploration portfolio, which is larger this year than in the previous years.
We have a focused portfolio on the Norwegian Continental Shelf. This is the framework you'll see in the next few slides as I run through the strategy in more detail. The framework is very simple and tangible. We have defined three key activities: execute, improve, or grow. If you can't put an activity into one of those boxes, we don't do it. Discipline, operational discipline and adherence to strategy is a very strong driver for our performance. Now, if you look at the performance on the improvement program, as I said, I'm really surprised on the speed at which the results are being generated on this activity program. We've chosen to focus on four key elements. As we reorganize the value chain, create alliances to reduce waste in execution models, increase quality, and increase flow efficiency.
We've taken an approach which is similar when it comes to our own operations by implementing lean and are on this journey of increased flow efficiency also in our own operations. There's a consistency between our focus on alliance and our focuses on our own organizational development. We are convinced that the digital revolution now occurring will fundamentally change the E&P industry and are determined to be at the forefront of that development and one of its architects. Finally, we are continuing to hone our own organization to meet the competency needs, the flexibility needs, and the entrepreneurial spirit needed in the future. Let's start with safety. Safety is our number 1 priority in all our operations. Our ambition is zero HSSE incidents in our operations.
You will also see that we've added cyberattacks to a part of the HSE agenda, which is focusing on safety. The reason for that is that with the growing digital mindset, new threats are occurring, and one of them is cyberattacks. We've focused substantially on rollout of energy efficiency, trying to be even better at CO2 density in our emissions, even if we are below the NCS standard. Finally, we have rolled out programs for managing barrier health to reduce the risk of high-potential incidents, and again, capitalizing on new digital tools that allow us to keep more an even better watch over our barriers. We had an incident on the 17th of December this year, where one of our team members did not come home from work.
I think as we end up the summary and the conclusion, we'll come to the conclusion that this incident was totally unnecessary. It's a reminder of the risk in our business. I can assure you that Aker BP is determined to determine the course and then implement all actions and activities necessary to take benefit and learn from that tragic and unnecessary incident. This type of topic has the utmost attention at our top management. If we move from safety to improvement, I think the conclusion is, yes, great savings are important and possible. They will require a new way of thinking and they will require attention and innovation on a scale that's higher than what we've seen so far. Our proven agenda is determined. We have already defined that we target a cost per barrel of $7 per barrel and a break-even of $35.
The key topics in our improvement agenda is defined: alliances, digitalization, lean operations, and a flexible business model. We have already seen that we're able to reduce our break-even cost on new productions down to $35 or less. I wouldn't be surprised if we, going forward, determine that the $25 break-even target that we now defined as a new continued improvement target, the ambition level turns out to be too low. In reality, there's an enormous amount of effort needed to be done in order to break down the cost levels, improve efficiency, and remove waste. They will require changes in our business model going forward. When we look at the achievements so far in the program, here I've taken the PDOs that we delivered this year.
Ærfugl, which is a Norwegian seabird, Valhall Flank West, which stands for itself, and Skogul, which I'm told is some sort of northern god. You can all see they follow the same trend. Volumes has gone up as a consequence of diligent subsurface work and data gathering. CapEx has gone down as a result of alliance work and improved flow efficiency, both in the execution and in the engineering phase. As a result, the break-even has been significantly reduced on these projects. One of them, the Skogul project, is a long tieback of 9.3 million barrels of oil equivalents on a gross basis. That would not have been possible without the improvement program run by Aker BP. This is tangible results. There are no changes to the scope. There are no changes to the way we decided to develop these fields.
It's pure improvement on the same basis, equal for equal. When we come to the balance sheet, as you've seen on the slide here. Also in the history, we have had a rapid deleveraging over the past two years. Currently, the net interest-bearing debt over 2P is about $3.5 per BOE which we believe is a really good level and a robust level to be on. The strategy in the recent years have been to retain strong liquidity position and ensure capital flexibility to be able to do transactions such as the Hess transaction in a very expedient manner. Over the past four quarters, from Q4 2016 to Q3 2017, our free cash flow has been three times the dividends. Today, we are introducing increased dividends. Let me go through in a bit more detail. In 2017, we paid $200 million in dividends to our shareholders.
For 2018, we will increase this level to $450 million. I have a very strong and clear ambition to increase by another $100 million per year to 2021, which mean a cash level of $750 million. The primary driver for this decision is threefold. We have a robust balance sheet and a low leverage and high flexibility. We have robust cash generation in our operations. Going forward, we are going to invest in projects with low break-even. Even if the CapEx is a bit higher than many expected this year, that money is being spent to realize project with $18 break-even on average. In total, we are convinced that it's prudent to increase the dividend yields for 2018, and we see the same development in the years to come. Moving on to flexibility.
Many companies have a tendency to over-focus on systems and structures. We truly believe that the individuals in the organization, the capability, the mindset, and the drive is as important. In our thinking, the Aker BP culture needs to be one of flexibility and entrepreneurial mindset, and where decision powers are distributed as far as possible. Some examples of what have been realized as a function of this strategy and this drive. It took us exactly one month from we decided to farm down on Valhall, till we had signed the agreement with Pandion. That one month included redoing the profiles, management presentation, screening of candidates, et cetera. It took us three months from the first indications of a leaking Christmas tree on Skarv to we had completed the first workover. Next couple of workovers will be done next year.
It took us eight months from we started looking at the Tambar field, till we had a rig drilling at the Tambar field, now completed the first well. This night, we cemented a 12 and a quarter-inch section section and we'll drill the rest of our section, probably already started. We have nine months reduction in the volume scope as a result of alliance activities. I must say, if there is one achievement that I'm extremely proud of, it's the organization's ability to execute, in 2017, with high quality and a high degree of flexibility. Going forward, Aker BP is a growth case in addition to offering attractive yield. I believe this is one of the key traits that make Aker BP stand out in the E&P universe. We see vast opportunity for value creation from our existing portfolio.
Growing opportunities as our improvement programs continue to yield results. From a base of about 160,000 oil equivalents per day to day, our efforts going forward is to maximize the resource utilization from existing hubs, leading to further profitable growth. We invest in data, have done so significantly in 2016 and 2017, and will continue to do so. We invest in new technology to enable this growth as well. Our current business plan has the potential to reach production of about 330,000 barrels of oil equivalents in 2023. This, as I said previously, represent a compound annual growth rate of 13%. This graph show how we moved up from last year's CMD. If you remember back, we had only two colors. Now we have distributed it in three colors.
In fact, we have accelerated about 80 million barrels into this time frame, even when we adjust for the change in ownership share on Valhall. We currently have a portfolio of development projects where the sanction part has a break-even of $18 per barrel and $24 in average for all our projects in the business plan. As I said last year, this same number was in the range of mid-30s. If you divide those two numbers, that's a substantial reduction in break-even driven by higher reserves and resources and lower cost and shorter execution time. In many ways, flow efficiency is key to this development, as it generate more resources into the existing work program as a function of time.
Again, you see that there is a direct connection between our focus on the improvement program and the results that are being generated this time in increased reserves and resources. If we break down these figures, the preliminary 2017 year-end results are 930 million barrels, which is up about 200 million barrels from year-end 2016. In part, this is of course driven by the increased ownership in Valhall, Hod, but it's also organically we see that we have converted more than two times the production if you exclude the increase in ownership share in Valhall. If we move to resources, we see the same picture with a significant volume growth. In this time, more than 300 million barrels in total. Certain projects, amongst lot of them, Gohta, have had negative revisions as a function of negative well results in the year.
We also see fantastic opportunities in the Valhall area, where we've been able to mature a number of new projects in 2017. In 2017, we converted 134 million barrels from resources to reserves. In many ways, you can see that this is also a function, both our focus on M&A activity, but also on our strategic focus on growth organically, and in particular, from our initiatives in flow efficiency. Moving on, I think the track record speaks for itself when it comes to M&A. We expect more M&A to happen also in the future. We have been disciplined, and we are being disciplined. There is no need for new deals that doesn't add to the story. We will continue to be disciplined and focus on shareholder value when we assess new M&A opportunities.
The screening criteria are as they were last year, financially accretive, operated assets, predominantly liquids. Of course, we believe that assets where we could utilize our strategy and our competency is value accretive. The portfolio on the NCS is, of course, focused on the NCS. Even more importantly is our focus around our hubs. As you can see on the map, we try to spend our resources where they can generate enough or more value. The portfolio currently consists of five production hubs. That proves diversification, but it also gives scale. It gives access to infrastructure, and it gives access to infill tie-backs acreage. We are operating approximately 100% of our production. That also means that we have an ability to apply our improvement agenda across the entire portfolio without delay. As I said, about 80% is predominantly liquids.
If you put the exploration program into 2018, which Gro is going to tell more about, over these assets, you'll see a trend. That is a trend where we're predominantly focusing on exploration in the areas that we currently define as our core areas, while we're also committed to continuing development of the Barents Sea at the same point in time. We state that our primary driver is to maximize shareholder value. When we compare ourselves to oil majors, European independent, and U.S. shale players, Aker BP has been awarded in the capital market for this strategy. We have delivered superior shareholder return over the past three years. I take this as an indication that we've had the right strategy, at least historically.
Going forward, we think that by focusing on each of these 6 strategic ambitions, we will continue to create shareholder value also going forward. I think this is actually quite an astonishing graph. Summing up the strategy. We still believe that the key framework is execute, improve, or grow. We believe that the key ingredients to improvement is to reorganize the value chain, focus on flow efficiency, keep an entrepreneurial and flexible organization, and make sure that we are in forefront of the digital agenda. We have demonstrated that this improvement agenda yield tangible results in 2017, and even more rapid results than we planned for a year ago. We have demonstrated further that the same strategy is also enabling Aker BP to maximize resource utilization in the area that we operate, and thereby increasing resources and opportunities in the years to come.
We have increased our organic growth opportunities from Capital Market Day 2017 to Capital Market Day 2018 quite significantly. As a result of this, we are able to pay out a dividend now increasing from $350 million to $450 million, and with a clear ambition to increase a further $100 million per year from now to 2021. In many ways, I think you can say that our strategy has at least worked in our favor, and we are going to continue the same activity set also going forward. If you can bear with me a little bit, I'll also take you through our assets before I hand over to Per Harald. Alvheim is in many way the poster child, and has been the, let's say, laboratory for the strategy development of Aker BP. It has yielded high production efficiency and production in 2017.
The business case has been to work relentlessly to maximize area recovery. Balancing execution, data acquisition by seismic and pilots when we drill, high-end utilization of downhole acquisition tools to better understand the subsurface, and combine that with efficient infill tie-backs through the implementation of alliances. This is the first place where we implemented the subsea alliance. In many ways, in 2017, this has resulted in great results. Viper and Kobra yielded much higher reserves, much higher production than we expected, and is a clear demonstration of the organization ability to turn around and react to new data and create viable, measurable results. The drilling of the Boa and Volund fields are other examples, and we'll come back to that. We are maturing further infill opportunities to arrest decline and minimize unit production cost.
Alvheim has been a fantastic field for Aker BP since we took over in the summer of 2014 and is a blueprint for what we are trying to achieve across the portfolio. Again, I think the result speaks for itself. From a steep decline from 2012 to 2014, we have been able to arrest that decline and not only arrest it, increase production again by putting new assets on stream. 2016 was the most active drilling year since Alvheim came on stream in 2008. The activity level is continuing. We have successfully increased production both by new tie-ins, but also by higher and higher utilization of the asset in terms of high production efficiency.
For the area as a whole, the estimated ultimate recovery is now almost twice at what it was when we planned for at the time of the PDO. The story is continuing. There are plans for several new developments in this area. Skogul, which is one of the PDOs we submitted last December, which is a tieback down to Vilje and from Vilje down to Alvheim, is an example of our commitment to resource utilization in developed areas. Skogul is also an excellent example of a project that would probably not have been executed without the implementation of the alliance model, reducing cost and execution time. We are maturing Gekko and Kobra East. Kobra East particularly as a result of the good results in Viper and Kobra. A project called Caterpillar is also being matured.
We are currently drilling an exploration prospect near Bøyla on something called Frosk or Frog in English. The results are expected shortly and may result in further exploration drilling in the same area. In addition, a number of new exploration targets are being matured. One of them is called Rumpetroll, which I don't know what is in English, actually. Deep Alvheim, both may be drilled in 2019. It is actually quite amazing that in this area we have seen so much drilling activity by further analysis of new data, new seismic, and we gathered new seismic just short time ago. You can see further opportunities. The focus going forward, safe and reliable operations, of which Alvheim has been a hallmark. We are continuing to interpret the 4D seismic. We also started to look at infrastructure debottlenecking to increase further tie-in opportunities, particularly of gas.
Moving on to Valhall and Hod. As I said, this is an asset that we took over operatorship in back end of 2016 as an asset that has surprised significantly in terms of available resources in the field. We produced about 35,000 barrels in 2017, net to Aker BP. That is at a 90% ownership rate. The unit costs have remained stable as despite lower production in 2016, proving that the improvement program does not only yield higher production, but also lower unit cost against stable or declining production. There is an ongoing drilling program at IP, which is this platform here. Now three wells are completed. We are running the completion on number four as we speak. More targets are being matured. The PDO for Valhall Flank West was submitted. The development is underway.
Also, we see increased opportunity scope in the area to increase recovery. When we move on to the Flank West, this is an unmanned wellhead platform. There are currently two unmanned wellhead platforms in operations at the Valhall field, this North Flank and the South Flank, so this will be number three. We have six well slots allocated to the scope, but another additional six slots to allow for further future expansion. Again, demonstrating our commitment to maximizing resource utilization in the area. I'm very pleased with how Aker BP team has been able to escalate the startup from originally planned around 2021 to now late 2019, with the resulting significantly improved economics. Volumes has also increased slightly from concept selection to currently residing around 60 million barrels of oil equivalents on a gross basis. The CapEx on it is reduced by almost 25% to NOK 5.5 billion.
The break even, as a result, is reduced by 16% to $28.5 per barrel. Another project that demonstrate that our improvement agenda is yielding tangible results. Why do we like Valhall and Hod? The resource in place is significant, almost 4 billion stock tank oil originally in place. We have produced only 25% of that to date. That means that there is significant upside potential to be produced over time. Today, we are stating that our ambition is to produce another billion barrels of oil equivalents of the Valhall area over time, which will raise the recovery to roughly 50%. What are the key ingredients? It's to continue drilling and drill out the area. We have significant drilling resources in place.
First, the IP rig as a stationary rig as a part of the field development, but also the Maersk Invincible, which is now carrying out P&A operations at a much more rapid pace than we thought possible. We started out that program at 120 days per well, and now we're down to 20 days and see a possibility to get down to 14 days per P&A operation. Which means, again, you can transfer cost and resources by focusing on flow efficiency to value creation and drilling new targets. We see opportunities from new technology. In this kind, we have exemplified it by the Fishbones completion technology, which will allow us to deploy multilaterals in the chalk. We see improved reservoir monitoring and data acquisition, both by using high-end measurement while drilling tools, so-called 3D tools. Also advanced modeling techniques to make faster and better decisions.
We see opportunities to scale up the water injection project, thereby gain more pressure support and more volumes. We see further opportunities to reduce cost and increase quality by digitalization. There's a large hopper of projects to be defined in the coming years. One of them could also be the Hod redevelopment project, which is high on our agenda, and where we will drill an appraisal well towards the back end of 2018. From a field that was probably looked upon as one of the candidates for P&A and field decommissioning, this is now turning into an extremely attractive opportunity in terms of growth. Moving on to Skarv. The overall performance in 2017 has been strong, despite challenges with two of the Christmas trees on the field. We have seen large increase in reserves, mostly due to the PDO submitted at Ærfugl.
We also collected new seismic across the area, which is currently being evaluated. We move on to Ærfugl, this is also an extremely interesting project. The resource has gone up significantly from around 200 million barrels to 275 million barrels, which is an increase of almost 40% since the time of concept selection. In turn, the CapEx has gone down 20% from $10.6 billion to $8.5 billion, which in result means that the break even is $18.5 on this project. This project is about two-thirds gas and one-third liquids, but it's still a significant effort carried out as we've developed the project. Phase 1 of this project consists of three wells, which will be tied in to the Skarv FPSO. The startup is 2020.
Phase 2 will consist of another three wells tied into basically the same infrastructure, back to Skarv, start up in 2023. For a project that has this kind of reduction in CapEx, it's also interesting to note that there's a lot of new technology elements. Electrical heated trace pipe-in-pipe. Hybrid vertical Christmas trees, which means that we will reduce the cost of future interventions, since we can intervene directly through the Christmas tree. In total, it also demonstrates that the alliance concept, and this time directly challenged in a market-to-market concept proved itself again. Looking at the Skarv area, we are not done with the Ærfugl project. We are targeting an average production cost for Skarv below $7, in line with our overarching ambition. There will be a step up in the exploration activity in the area.
Kvitungen/Tumler, which is on our firm drilling program, will be drilled soon. Gro will talk more about this later. We are maturing further exploration and follow up on exploration activity in the area in 2019. We also have an extensive program in place to maximize area recovery. The processing of the 4D seismic that we collected in 2017 is ongoing. Reservoir work for the Gråsel discovery is ongoing and may turn into a field development project. We are also assessing completion techniques to increase the recovery in the low perm Tilje formation based on early data from the 4D data set. In addition, we're, of course, working to reinstate production from the shut-in wells. One was put online already.
Took three months from shut down to back online, we are firming up plans to recomplete the other two wells in 2018, probably as the first activity on Deepsea Atlantic. From Vøring basin to the south to Ula. Production in Ula in 2017 was 8,000 barrels of oil equivalent and gave a high unit production cost, about $40 per barrel. You may feel that Ula is then uninteresting in the Aker BP portfolio. Quite the opposite. We consider this a huge opportunity. It's an under-invested asset with activities ongoing to improve productivity and cost. One of them I've already talked about is the Tambar redevelopment project. Another one is the Oda tieback and modification project. If we look at this more closely, Tambar redevelopment is well underway.
The Maersk Interceptor has completed one well and has run the casing on well number 2 and are about to enter the reservoir. A gas lift model is being installed while we have Maersk Interceptor in place due to the increased bed capacity. We expect first year oil later this year, as soon as the wells can be completed and the gas lift program completed. In addition, there's very strong synergies towards Ula from Tambar and the Oda project. The Oda is a third-party tieback operated by Centrica, where Aker BP own 15%.
The increased volumes will, of course, drive down unit production cost. Even more importantly, the increased availability of injection gas will increase the numbers of wells we can run on so-called WAG, which is water alternating gas, where we inject water and then alternate to gas to maximize sweep efficiency, which in turn will yield increased production in the years to come. We expect increased production in the coming years to result in a further reduction of unit cost down to about $20 per barrel, about half of the 2017 level. In addition, we are maturing further opportunities, more infill wells to be drilled on the Ula main reservoir.
To expand the use of WAG and injection to maximize drainage in the area, we are evaluating appraisal of the Ula North prospect and also Ula Triassic, which is a reservoir at Ula main field that is only being produced through one well. We are also assessing further near-field exploration. It also is worthwhile to note that we also in Ula gathered 4D seismic this summer. All in all, I believe this also demonstrates our ability to turn around and put profitable projects on fields that may have been considered to be less attractive in the past. Moving on to Ivar Aasen and Hanz. Ramp-up of production on Ivar Aasen has been extremely expedient with high quality. We are about one year ahead of our plans, and the 2017 production ended up at about 18,000 barrels of oil equivalent net to Aker BP.
The uptime and production performance has been excellent with a bit of challenges on the power supply from Edvard Grieg, resulting in some downtime, particularly on the high energy drives across Ivar Aasen. The PDO scope is now completed, and the platform production was reached one year ahead of plan. I think we can conclude at this point in time that Ivar Aasen has been a successful project for Aker BP. We're not giving up there. There is a number of further activities planned in 2018 and 2019. We will drill two new water injectors and enhance appraisal well in 2018. We have already started planning on an IOR campaign in 2019, and we are maturing exploration opportunities that may result in new tie-backs in the area. Ivar Aasen is also quickly becoming Aker BP's laboratory for operational improvements, particularly as it pertains to digital tools.
We are optimizing the use of the onshore control room, which will mean lower cost, better production, but more importantly, pose a real laboratory for how to digitalize our offshore operations. New technology, combined with digitalization and lean work processes, is going to lead the way to more efficient offshore operations. In the same manner as the Alvheim field has been the role model for our focus on resource utilization and alliance work with the vendors, we believe Ivar Aasen will be the role model for efficient operations. This doesn't come without effort. In 2017, we have increased the M&O budget significantly. Currently, there are more than 70 defined, seven-zero, defined projects ongoing across the portfolio. And we have increased the numbers of M&O spent by about 40%, four-zero percent, since 2016. This is quite contrary to what you see across the Norwegian Continental Shelf.
You can ask, why do we do so? That's quite simple. We believe that it's consistent with our strategy to invest in this asset to make sure that we have lifetime to utilize the resources in the reservoir. Also, we believe that by implementing new ways of working with the vendors, we can increase flow efficiency in the maintenance operations and thereby reduce cost. When you move on to drilling, when we were at the Capital Markets Day last year, there were two ongoing drilling operations in Aker BP. Now there are five. Maersk Interceptor is currently drilling at Tambar. We'll move on to drill water injectors and Hanz appraisal. Then we sublet to the Oda license to drill Oda production wells. Transocean Arctic is currently drilling the Frosk or Frog exploration well.
We'll move on to drill the Raudåsen exploration well and then go back to drill the Hod appraisal well that I talked about, which is in this slide called the pilot. The Valhall drilling platform will continue to produce wells on the Valhall main field. The Maersk Invincible is continuing its P&A program. Also note on this slide that we expect the P&A program on Valhall to be completed by Q4. This is a result of a continuous improvement effort by the Invincible team and Maersk, which have slashed the average P&A activity from a planned 120 days to a current 19-20 days and targeting down to 14 days. Then Deepsea Stavanger is coming on board. The first well it will drill is the Kvitungen and Tumler.
Then move on to do the Skarv workover before it moves up to the Barents Sea and then comes back to drill Kameleon South on the Alvheim reservoir. In total, I've gone through the strategy. I've demonstrated how that strategy generates tangible results in terms of increased shareholder value. So increased resources, increased dividend, and an increased scope for further growth. As you can see now that I run through the execution part and also demonstrating the work program in 2018, you'll see the same traits, the same strategy and the same activities, also in 2018. I think the key elements of Aker BP strategy also demonstrated by the execution, can be summed up as follows. We believe that acting together with our vendors, we can reduce cost, increase flow efficiency and improve activity.
Aker BP is committed to resource utilization on the Norwegian Continental Shelf, by improving the flow efficiency in our operations, the data acquisition, and the execution of our tie-in projects. Last but not least, we have a significant hopper of increased production and increased activity going forward to support that dividend yield, also in the future. All of these projects have a break even of roughly $24 on average across the portfolio. There's more to be done. The improvement journey has just started, and even if we are happy with the results, I can assure you that Per Harald feel every single day the need to improve a little bit more. So I'm pleased to introduce Per Harald. Per Harald Kongelf, which is our head of improvement in Aker BP. Floor is yours.
Thank you, Karl. Our business is constantly under attack from external forces, it being forces of nature, volatile markets, environmental concerns, technological developments, regulatory framework, and not least competition both within the industry and from alternative energy sources. In order to stay ahead of the game, we believe the ability to adapt and improve is essential. Hence, improvement is a strategic imperative for Aker BP. Aker BP is running a comprehensive improvement program to maximize flow efficiency and remove waste in our value chain. Our improvement agenda currently covers four broad topics, which Karl already have introduced you to. Improvement for business transformation, as shown on this slide, all of which are interlinked and intertwined with all our improvement activities and initiatives. Today, I will cover two of these topics in more detail.
Let me start with alliances, an area where Aker BP has chosen a different path from many of our peers. Our suppliers account for approximately 85%-90% of our cost, and this fact demonstrates the strong logic for how important our suppliers are for our competitiveness. At the same time, they also represent a large share of the opportunities and risk we face every day as an oil and gas company. Hence, they are in the core of our value creation. In such a context, we need to deal with our suppliers with a strategic mindset and approach. We believe that the present way of operating and managing our supply chain through traditional transactional procurement has, over the last 15-20 years, demonstrated its inefficiency to deliver improved performance and value to the E&P industry, and hence deserves to be challenged.
In our view, this unsustainable relationship between operators and suppliers cannot continue if we want oil and gas to be a competitive energy resource in the future. The question we asked ourselves was, should we try to improve the traditional transactional approach with a large number of suppliers, with little continuity in the relationship, with a lot of ineffective interfaces and with disaligned incentives, and with a huge non-value-adding cost to facilitate this process, like the bidding cost? Should we look for inspiration from other industries like automotive, and work with a few strategic suppliers in a much more collaborative manner in an end-to-end integrated flow efficient and long-term value chain with shared incentives? We are convinced that it is the time now to try to do what other industries have already been doing for decades.
We have established an alliance model which aims at solving the problems we have observed with the traditional model. Through 2017, we have progressed significantly with reorganizing our value chain and have formed long-term strategic alliances with some of the leading suppliers in our industry. We intend to continue to explore the possibility for more alliances as well as systematically and continuously improve the alliance way of working to the best for our partners, the industry at Norwegian Continental Shelf, and of course, for Aker BP. What do we want to achieve with our alliances? The basic answer is that we want to remove waste from our value chain. We want to make each other good, leverage each other's capacity, technology, strengths, and skills, ensure that the best employee does the job regardless of where we are employed. Avoid duplication, avoid non-productive bureaucracy, and non-value-creating work.
Simply work as one integrated and seamless organization with the same goals and incentives. We want to see the entire value chain in an end-to-end seamless way and to optimize the flow efficiency and productivity of such a chain together with our partners and also with the digital lenses on. As a result, we also expect quality and performance predictability to be at a much higher level, and we will become more flexible and scalable. Hence, able to address the expected cycles and volatility of our industry in a much more efficient way. To achieve this, we think the alliance partners need aligned and attractive incentives driving the behavior and results we want. In short, we want our alliance partners to be financially robust and earning money through a shared risk and reward mechanism.
Alliance way of working is enabling very early involvement of our supplier chain in project and field developments, which gives us the opportunity to move faster and with higher quality directly to the realization phase of the project. We have already experienced this effect in several of our projects, which also Karl already have pointed to. Said that, the alliance will only survive if it, in a transparent way, can prove that it provides continuous productivity and performance improvement beyond what the traditional transactional supply chain model can offer. Hence, we will benchmark our alliances with traditional models in our industry going forward. We need to prove to ourselves and our surroundings that we outperform the classical and transactional-based supply chain. Remember, all our alliance partners are selected and will be selected after an open, competitive bidding and evaluation process.
Hence, the alliance starting point is always that the selected partners are competitive. We think the improvement potential these alliances has got to work with is huge, given the fact that the waste in our E&P value chain and in our industry is so massive. We have already started to see positive results from this work. This chart illustrates a project involving two new infill wells at the Volund field, which is the first project completed under the alliance model. This project was delivered in 2017, nine months ahead of schedule, and at a significantly lower cost than planned. As the chart shows, the alliance contributed to a 30% cost reduction compared with the starting point.
We are now rolling out the alliance model in all our main projects, including the three project that were sanctioned in December, and we expect to see more positive effects on cost and schedule as we move forward. On the subsea scope on Valhall Flank West and Skogul, we can already now see that the alliances contribute to deliver as shown on the waterfall of this slide. Aker BP, we are convinced that the alliance will be a key to be able to meet our break-even target of $35 per barrel or less, and not least, also be able to deliver them according to cost, time, and quality targets going forward. We also expect the alliances to deliver even greater improvement in the longer term, and we will systematically work with our partners to achieve this.
These improvements will be harder to realize and will request innovation, but we believe they are critical for our long-term competitiveness. My second improvement topic is data and digitalization of E&P, which, by the way, is an integrated and very important part of the improvement and development work we will do with our alliance partners. Hence, a very important selection criterias when selecting alliance partners is how they tick the boxes for our digital evaluation criterias. Technological shifts offer completely new opportunities for applying digital solutions for effective data sharing and insight. In our view, there is no technologic deficit in the world, but more a lack of ability to put it into use and to learn quickly from other professions, companies, industries, and countries being in the lead. We are therefore actively seeking inspirations from others and try to be ahead of the pack.
We are convinced that anything that can be solved by software should and will be solved by software in the future. That digital has the potential to radically transform our business and industry, and further, that this transformation will provide a competitive advantage for early movers. We believe the successful industrial companies of the future are truly digital enterprises with physical products and asset at the core, augmented by digital twins, digital interfaces, and data-based innovative insights and services. These digital enterprises will work together with customers and suppliers in a collaborative, industrial, highly efficient digital ecosystem. As a result, we will see changes in how we are organized, how many people we employ, what skills we need, operating models we apply, how we interact, what business models we use, what players we work with, and not least, with what productivity, flexibility, and quality we can run our business.
In other words, it will provide radical improvement to this industry's productivity and disrupt old ways of working. Watch out, the journey has just started, and it moves fast. The most important topic for us at Aker BP in digitalization of the company is data, the glue in the digitalization. We need to get control with and have easy access to high volume and high-quality data, which we can trust at all time. Industrial companies, including E&P companies like Aker BP, generate large amounts of data that we increasingly want to use systematically and commercially. We cannot overstate the value of ownership and access to high-quality, reliable, and evergreen data. This is priority number one in our digitalization efforts, get control of our data and make them easily available for everyone that can help us with giving insight and create value out of them.
This also includes the importance of having good governance and structure around access control, security, and quality of all data relating to our business at all time. The key enabler in this process of removing the data silos and liberating our data is the heart, the high-performing data platform. We further believe that a clear separation of data and algorithms is necessary to extract value in an industrial context. Hence, we focus our work on developing a data platform, as well as developing numerous applications, working on the top of the data platform, consuming data to create insight and value to Aker BP.
While some companies establish large consultancy-driven projects to deliver a custom, closed, and proprietary data platform, Aker BP has decided that we will try to enable the birth of an open, shared, cloud-based, and commercial solution that continuously scales and improves independently and across companies, industries, and countries. A data platform where Aker BP owns and controls its own data and at the same time enable data sharing with selected partners based on efficient right to use arrangements. We will, through the data platform, get a unified data architecture of operational data where all relevant data will be easily available for the user all the time on any device with minimal latency from any location. We will require that all equipment and systems delivered to us have open APIs complying with our standards and specifications and deliver data on non-proprietary and well-defined data formats.
Applications and algorithms will be connected to the data platform via open APIs. No customized silos with vertical integration or lock-in, or data capture in applications will be allowed. There are several interesting industrial data platform concepts in the market, including Siemens MindSphere and GE Predix, which on the PowerPoint format, is meeting all our expectations and requirements. However, our view last spring was that these market alternatives were in their infancy. Hence, we decided to follow an alternative route. We have therefore, as you probably know, established a long-term research and development cooperation with a software startup company, Cognite, led by John Markus Lervik, known as the founder of Fast Search & Transfer and Cxense, a company where Aker BP also has a 10% shareholding. Cognite is a technology company with the ambition to develop and commercialize a state-of-the-art data platform meeting all Aker BP's requirements.
When the platform is developed, will it be delivered to Aker BP as a software, as a service in the cloud. Cognite aims to recruit some of the best brains we have access to in Norway within data science and have already signed a high-quality team of approximately 50 people co-located with Aker BP here at Fornebu. Already today, as we speak, all operational data from all our five Aker BP operating production hubs are available for ourselves and our selected partners on our Cognite data platform. We have uploaded all historical data back to 1986 and are now streaming live data from close to 200,000 sensors into the Cognite data platform. The exciting thing is the high speed and low cost at which this new technology can be put in operation. We started feeding data into the platform in August.
In November, we were up and running, and the backfill of historical data was performed in just a few weeks. Amazing. We have now started to combine the time series data from the sensors with contextual data like tag mapping towards 3D asset models, P&ID process files, maintenance logs and data, as well as ERP data. Hence, our first step towards the digital twin of the asset has started, this will be shared with our selected partners to create insight and value for Aker BP, but also for our partners. The idea is very simple. It is that this industrial data platform will enable Aker BP, together with our partners, to make our data a strategic resource for accelerating performance, innovation and decision-making, will enable efficient interaction and digitalization of our value chain and the NCS E&P ecosystem, leading to a highly competitive business and industry.
Aker BP has, over the last year, taken important steps and had the first positive learnings in its digital transformation. With strong support from our largest owner and a highly engaged top management team, led by an even more engaged CEO, we have formed a digital vision and roadmap for the company, supported by a significant pipeline of digital use cases and a number of key digital initiatives to be solved in the months to come. Even more important, we have matured the vision and roadmap for digitalization together with the entire organization, created understanding and engagement in all parts of the business, also offshore. This digital ambition has also been reinforced by us focusing our entire research and development efforts and funds on innovation and technology related to digitalization and subsurface. In 2018, estimated to be a spend of approximately NOK 430 million.
To deliver the specific use cases and digital initiatives we have identified, we combine the best domain competence from Aker BP, but also from our strategic partners with strong software competence in companies like Cognite or its likes, in an integrated program, combined with a test-and-learn approach to be able to move fast. In parallel with developing the Cognite data platform, are we also developing applications running on top of the data platform, working on the data in the platform to solve tasks defined by our use cases. This is to test and verify that the platform and platform architecture and APIs is working, but also to get some early wins with regards to getting insight to and value out of our data set. Now I would like to share some example of initiatives and use cases which we are working on with you. I will sit there.
Yeah, sorry. We have already started sharing operational data with our suppliers, with Framo being the first OEM to get access, free of charge, to live data from their own equipment on Ivar Aasen through the Cognite data platform. I can tell you, it works and the feedback is promising. This opens up opportunities for them to identify improvements and deliver better products and services to us, which they are working on at the moment. They are also trying to develop remote operational functionality and diagnostics, as well as to identify further improvement on their equipment packages for future projects in our portfolio or on the NCS. Another initiative where I think we have come very far over the last months is on the use of tablets to support our offshore operators.
Today, a tremendous amount of time is spent on searching for information and on manual workflows and tasks offshore, where relevant and trustworthy information and documentation is absent or very hard to find. By giving access to relevant data and information stored in the Cognite data platform and displayed on a tablet at the location based on the work to be done and looking at the equipment to work on, significant time can be saved and risk reduced. It might sound like something that will not be ready for years, but we have already tested a first version of this on Ivar Aasen and Valhall and aim to deploy it in operation by the end of 2018.
To kickstart piloting and testing how the digital oil field of the future should look like and how it could be operated, we are in 2018 also planning to use Ivar Aasen as an advanced test case as a laboratory. Examples of what we are planning to do is we plan to develop the first version of an Ivar Aasen digital twin on the Cognite platform, including real-time data. We will test and develop digital tools and applications for operational support and data visualization, working on the Cognite platform. We will work closely and integrated with our key OEMs in operations, for example, Framo, to improve performance of the plant and to do maintenance more efficiently based on using digital technology, like predictive maintenance based on machine learning on top of the Cognite platform.
Also start testing, using, and developing the remote operation functionality, which Ivar Aasen already are equipped with. By end of 2018, we hope to have a very clear understanding of what it takes to have a first version of a digital offshore operating model for the future. The last example I would like to draw your attention to is the PUSH program that we are running in joint collaboration between Aker Solutions and Aker BP, where the objective is to radically improve the way offshore projects are engineered. The objective of this program is to accelerate the transition to a fully automated and digital field development project by developing a suite of software applications aiming at reducing execution time and reduce costs significantly from discovery to operation.
The initial focus of PUSH has been on developing digital early phase topside engineering tools, enabling fast and advanced technical and economical concept selection. We are currently also developing the first versions of solutions for detail engineering and fabrication. PUSH will ultimately provide a digital red thread from engineering to operation and generate 3D twins of the platform for use in all phases of the project. We have so far released five applications and have three more in development, and three of these applications have already successfully been piloted on our NOAKA field development project in the concept selection process and has contributed to improvement in the project. This application will consume data from the Cognite platform.
The progress we have had and the learnings we have gained on digitalization this last year makes me convinced that we are moving in the right direction and progressing much faster than we initially thought would be possible. We need to fix one major issue, access to enough high-quality data to take advantage of what the new technology will offer us, hence, we need data liberation on the Norwegian Continental Shelf. The current state of affairs in the E&P business with regards to data is a world of data silos, low-quality data, and even lots of dead data. A lot of industry data are broadly inaccessible or stranded. An advanced oil service provider has at least 100 operational data systems with 4,800 active integrations and with 500 connections rebuilt every year.
The typical large oil and gas operator can connect less than 60% of its 4 million sensor identifications to equipment and backfilling of historical data, which we just have done, is very often impossible at a reasonable scale. Data is strategically important and valuable, and even more valuable if you are able to create good insight and value through the data. For example, through applications for machine learning and artificial intelligence. The latter will require that you also have enough data and of good enough quality. Very few, if any, of the operators will have that today. We believe a data liberation is needed. We need to transparently share, we need to have open standard APIs, and separate data and applications to unlock data and enable efficient insight and value creation from our data to the benefit of the whole ecosystem on the Norwegian Continental Shelf.
Also, the subsurface data related to seismic exploration and operations should, in our view, be shared and processed by using more open-source software. We think we also need to move subsurface towards an open-source logic. It has just started with 3D multiclient seismic, it cannot and will not stop there. New and cheaper technology will enable workflows of processing and interpretation of data to be shared openly, and we hope that NCS sooner rather than later will be based on an open access to subsurface data for all players, as well as open sharing of workflows to process and interpret the data and open sharing of digital workflow recipes. Productivity gains from such data sharing and analytics on the Norwegian Continental Shelf have a potential to significantly lower the cost per barrel. Even a company like Aker BP does not have access to enough data.
We think it will be very important to share data across operators and companies in the future. The benefits of such sharing of data are so plentiful that they should obviously overshadow the challenges. Hence, our invitation to the industry is, let's get started and share data. Improvement is a strategic imperative for Aker BP. In Aker BP, we are therefore running a comprehensive efficiency improvement program, working integrated with our strategic partners, looking at our shared value chain and work processes with both the lean and digital lenses on, with the objective to get out as much waste as possible, create as high flow efficiency as possible, and still be able to swiftly innovate the way we do our work and business. We are working with digital, with the aim to be an industry reference point for digital project and execution.
We have designed a structured and proactive approach to our improvement work to ensure continuous productivity and quality improvement in all parts of our business, and to be able to measure that it actually is happening. All this to improve our joint productivity and margins, which will enable Aker BP to meet our targets of not sanction any project unless they meet a break-even of $35 USD per barrel or less, be able to operate our asset at $7 USD per barrel, including tariff, as well as cut the time used from finding a resource we view interesting to have oil on deck in half. Bottom line, will this ensure that Aker BP stays competitive and profitable also in a market with high uncertainty, high volatility with rather low oil prices? Many thanks for your attention.
Thank you. We take questions from the audience, either here in the auditorium or on the web. Who would like to start with the first question? The one just here.
Teodor Sveen-Nilsen, SpareBank 1 Markets. Thank you for a very detailed update. A couple of question from me. First, on what color, what you mentioned on the break-even level of the sanction portfolio, $18 per barrel. You also mentioned that's of course driven somewhat by lower market prices. Going forward, maybe we should not expect that much lower market prices. Further improvement to that break-even level, where should we expect that to come from?
Excellent question. Well, first of all, I don't think a lot of the improvement you'll see is from lower market prices because a lot of these improvements happened from 2017 CMD or decisions made in 2015 and 2016, and the market at that point in time was not exactly optimistic. A lot of this is actually driven by improvements in flow efficiency, and other improvements that has a net effect to increase productivity. As you saw in the Volund case, we've tried to be quite clear on what is market effects, and what is actually improvement effects. Now, it's easy to conclude that we've come to an end, and I would be happy to say that we had a productivity that was extremely high, and there was nothing more to gain. In reality, I don't think that's the reality.
I think there is still a lot of productivity gains to be had. There are still a lot of interfaces that aren't exactly frictionless. Digitalization, as Per Harald talked about, we just open up that box. It's going to radically change how we're able to execute and how the swiftness and the quality and the cost, and it's happening far faster than we had imagined a year ago. Hence my conclusion, I think you might quickly find that the target we set out with first 35 and then 25 turns out to be not ambitious enough. I believe that there's still a lot to be done in terms of increased efficiency on the Norwegian Continental Shelf.
Okay. Thank you. Then, while talking about digitalization, looks like, at least this far, you use the Cognite platform mainly on your operated field, if I'm right. How could the Cognite platform impact the Sverdrup in terms of break-even levels, OpEx per barrel, phase two CapEx? Yeah.
The Cognite platform in itself is a data platform. It's commercial. Anybody can buy it. We are instrumental in developing it. We have never had the intention, nor do we actually have the right to limit Cognite's use of that platform. Quite the contrary. We hope that there will be many users of that platform. I would be extremely happy if it turned out to be Sverdrup as well. That is actually one of the key issues here is that we believe that proprietary solutions on a company-by-company basis is not going to drive sufficient speed, sufficient improvement, and sufficient quality.
I think what actually amazed us was the velocity it actually happened in. As Ivar Aasen said, we started uploading up in August, and now we're done. We actually assumed that that would take a year, maybe a year and a half. There is something happening in this industry that is going to fundamentally change the way we think about it.
Is Statoil a client of Cognite?
I think Cognite should answer that. I think they run a couple of projects for Statoil. I'm not aware of their state of discussions.
Thank you.
Do we have further questions in the audience here? Questions from the web, Jonas? None. Yeah, we have one question here.
Hi, good afternoon. It's Nikolay Kuzmanov with Jefferies. Just maybe moving away from Cognite, just on your numbers for the growth to 330,000 barrels by 2023, is there any risk number that you provide with that, not necessarily a detailed list of what non-sanctioned projects go into that? Maybe just a question on the dividend and the recent increase. Has that been helped by the oil price rally? Do you see any risk if the oil price comes down that you won't be able to hit that $100 million growth per year to 2021? As part of that, is the $750 million sort of perceived ceiling at the moment given the current business plan? Thank you.
In the quarterly presentation, we usually have a rule, Alexander Krane, our CFO, he does the difficult ones, so he should really be doing this. When it comes to this growth, we apply the same methodology that we used. That means that what you see is our expected numbers. That means that it's not a kind of unrisked optimistic, it is our plan assumption. Second, they're all named projects, there's no exploration upside, there is no M&A possibility, et cetera. It is what is in our current business plan, what we call long-range plan with the current economic planning assumptions. That should give you a little bit of an idea of how that figure is being constructed. What we've really done is to accelerate and increase the level of projects.
Later in my presentation, when it comes to growth, I'll show you the list of projects. You can find it in the handout as well. When it comes to dividend, in addition to the increase in dividend yield, we also stated that we believe that this could be done without exceeding the 1.5 times level of gearing, which is another illustration of how robust we believe this case actually is. If you get back to your office and you put all these numbers together, you'll come to the conclusion that the oil price can actually drop quite significantly without us having to redo that policy based on oil price changes.
Actually, as we sum up, we believe again that the balance of a robust and reduced leverage, high cash flow from existing operations, which you'll also see later today, and a break-even from the current portfolio that is significantly below what anybody guesses going to be the forward oil price is a robust and good basis for a new dividend policy for the company.
Very good.
I think we have time for one more question before we go for break.
Thijs Berkelder, ABN AMRO. You prefer to be operator on your fields. How should we see Johan Sverdrup in that perspective on the somewhat longer term?
If we would love to be operator on Sverdrup, the answer is yes. I'm guessing that's not your question. Sverdrup, of course, is an excellent field to be a part of, and Statoil is doing a really good job as the operator. At this point in time, we're happy with the position we have on Sverdrup.
Okay, we primarily have seen a lot of acquisitions. Do you also have a divestment strategy?
That's a good one. Yes, we have just divested 10% in Valhall. Not necessarily because we wanted to, but because we had to. The way we think about this is as we're operating almost 100% of our portfolio, we feel that we have a very good control over the content of that portfolio, the upside and the downsides, and the opportunities therein. It's almost implicit in our strategy that when we go in and acquire an operatorship, it's because we like the portfolio. That doesn't mean that we will not selectively divest if we believe that that is value accretive to the shareholders. An example being on the Valhall case, we have said that us ultimately would like to own about 65% or two-thirds of that asset. At some point in time, we may choose to act on that strategy, either through cash or through a swap.
For the time being, we think that this asset is highly attractive and a good place to be. We'll have the same type of approach to divestment as we'll have to acquisition. We have a very clear, very firm strategy, we are able to move swiftly if the opportunity arises.
Finally, question on the alliance model. You primarily bank on, let's say, key contracts or key suppliers to you. How do you more or less insure against the risk of one of these suppliers failing for whatever reason? What kind of systems do you look at now? We're now still in an oversupply market, let's assume that in five years' time when these framework agreements more or less end.
Okay. Your question is what happens if one of these defaults or otherwise fail from a commercial standpoint, right? Okay. That's a good question. Several points of departure to that answer. The first one is, of course, that we validify the solidity of every contractor and partner in our partner universe. It's, of course, a part of our assessment whether or not they have a chance of ending up where you are discussing it. Then, of course, you can't guarantee that there aren't off-event events that will change that picture as we move into operation. In this case, we try to, by being transparent and open, to be very early in identifying such solutions, and if necessary, participate in finding a solution. Now that being said, the partner universe that we have created so far, we don't really see a lot of risk.
It is a topic that is very core to our assessment early on. It's also interesting to note that we see that the application of these alliance models increase competitiveness to the partners on the alliance models and also allow them to identify waste and non-productive activities in their own business model, which in line helps them improve and accelerate their own improvement programs, which we see they then utilize in other contracts against other E&P companies which do not necessarily run the alliance model. We actually believe that by running the alliance model with our contractors, we are making them more robust than the opposite.
Okay. We have one very final question at the front here. The microphone, please.
Thank you. It's Anders Holte from Danske Bank. Just reverting back to the M&A comments. It's been such an integral part of your success so far. Just wondering how you see the opportunity set out there on the NCS now compared to 12 months ago. Also what movements are you seeing on the seller side? Also give it a reference compared to last year. Of course, the opportunity set out there. Is it on the increase? Is it coming more? Yeah. Any thoughts would be good. Thanks.
We start with the M&A opportunities. Well, it's quite clearly been a very active year. A lot of players have done strategic moves in 2017. That, of course, has had a certain impact on the set of opportunities. We've also seen that there's been an influx of opportunities. We've seen that these strategic moves made by certain players have also impacted other players' view on the same situation. In sum, I'll say that the activity set or the possibility set is maybe somewhat reduced, but not necessarily reduced by the number of transactions that we've seen in 2017. On the player side, I think it's quite clear that we see more PE-backed entities. We've also done one of these transactions on the Norwegian Continental Shelf.
We also see that some of the strategic companies, such as the Maersk Total transaction, is also innovative in terms of nature. You could elaborate from that there's more competition in the M&A space. I think for Aker BP, this kind of sums up to being even more focused on what is value accretive, but also disciplined as to what kind of transactions we go into and what kind of pricing we accept on those transactions. On the vendor side, which I think was your second question, we see a possibility for consolidation, obviously, in the vendor space. We see that our vendors are increasingly robust as they're getting their improvement programs to work. They seem to have come over the first kind of wave or the last wave of cuts. We see the quality rising on the deliveries, et cetera.
My assumptions is that as you move into 2018, you'll see an increasingly robust service sector, I wouldn't exclude the possibility of consolidation in that sector either.
Thank you. Cheers.
Thank you. That concludes the Q&A session for this time. There will be an opportunity to ask further questions after the second session of the day. Now we do a quick stretch of legs, coffee refreshments next door, and we'll start again 15 minutes past the hour, 3:15 local time.
I suspect you might be a bit tired of hearing my voice, so I'll shortly lead over to Gro. Before I do so, I just want to draw your attention to a couple of the non-FID projects in our portfolio. First and foremost, starting with the Johan Sverdrup project. It truly is a pleasure to see that project progressing. Massive construction activity carried across three continents and now we are 80% complete on time, on schedule, and on cost. The drilling platform has been integrated. This is a picture from the heavy lift at the Klosterfjorden where the drilling platform was put together. We've seen the riser platform being ready for transport. We assume that to happen in February. We've seen nine water injectors now pre-drilled and completed with excellent results.
It's always also a pleasure to see that the CapEx is continuing to come down following the trend that we've seen previously in this project. We're now estimating phase 1 at a nominal of NOK 96 million with a break-even oil price of a little less than $20, starting to almost compete with Alvheim. The full field CapEx in the range of NOK 132-NOK 147, which will yield an all-in break-even of about $25 per BOE. We're in the middle of the phase 2 PDO run and assume that the PDO will be delivered in the second half, probably as the back end of 2018. This project is going well, and as I previously said, we're really happy with Statoil and the job they're doing as operator on Johan Sverdrup. Moving to another important project for us, it's the NOAKA project.
The NOAKA project is the area between Oseberg and Alvheim. This is an area that's been marked by several operators who have tried to make the small, really smallish accumulations in the area, economic on a standalone basis, but has so far failed to find a solution. During the years between starting with acquisition of Svenska in 2015, Aker BP has cleaned up the area such that it is now three oil companies that are owning the licenses in the area. That is Statoil, Lotos and Aker BP. We have established an area forum to evaluate the joint area development of this North of Alvheim, Askja, Krafla, NOAKA area. Currently, two concepts are being evaluated.
A PDQ, which is a hub on solid legs with a processing platform in the middle of the area, then tie-backs, either from subsea installations or normally not manned installations similar to the Valhall Flank West on each of these accumulations. Even if the accumulations themselves is smallish in nature, the entire area add up to a resource base in the range of 500 million barrels of oil equivalent plus, which is a quite substantial amount of reserves. This number include tie-in from Frigg and Rind, we believe concept selection will be targeted in Q1 2018. Our assessment is first and foremost that the concept selection will have to be done based on what facilitates the highest recovery in the area.
As you've heard before the break, in Aker BP, we have a very strong belief that resource utilization and maximization of oil exploration potential is the primary drive for a high economic yield in an area. Second, we believe that the NOAKA area is still prospective with a lot of possible future tie-ins from exploration projects, we have mapped the area and identified an unrisked potential in the range of another 400 million barrels. We believe that the PDQ alternative of those two currently being assessed is the most robust one in terms of future tie-ins as well. In conclusion, we believe that the PDQ alternative will have an acceptable break-even price and a high value creation. We believe that there's relatively low risk with a PDQ platform based on conventional design and proven technology.
As you've seen, we already started working with digital delivery models to make sure that we can shorten the execution time, increase the quality, and also make this project a watermark project for the involved parties in a new execution model with much higher productivity than previous ones. We believe that the area fields should be developed either as subsea or as unmanned welded platforms. That's dependent on the specific requirements on that specific field, we believe power should be supplied from shore. We're working this project with Statoil, we're very clear on our mission to get to a concept selection within Q1 2018. Really, for the first time, we see a possibility to develop this area economically, which is a quite interesting case, particularly as it's been tested several times in the past. There was a question regarding the project inventory.
I'm not going to run through the list. I'm sure you can find a way to do that yourself. As you will see, if you compare it to the capital market day presentation last year, this list is expanding in nature. It's expanding in volumes, it's expanding in the number of projects included on the list. You can also see that the predominant part of these are operated. That means that we'll be able to utilize our improvement agenda to do what we have done on Volund, on Skogul, and on Valhall Flank North, to continue to drive down the break-even cost and up the reserve estimates. With that, I'll leave the word to Gro to take you through the exploration program for Aker BP, as well as the exploration strategy. Gro?
Thank you, Karl, good afternoon. Exploration also contributes to long-term growth to the company and our agenda, and also value creation. During the two last years, we have discovered about 100 million barrels net to Aker BP. We have also, during the last four years, high-graded our exploration portfolio and built a strong position from south to north on the shelf. We have, in fact, done that by actively seeking and access new licenses through the APAs and the bi-yearly licenses round and through strategic BD activities. Some of the new licenses' areas have a potential even to build new core areas with production. We have invested in more than $50 million in new high-quality seismic data, both around producing assets and in growth area, but also in frontier areas.
This gives us, in fact, also a unique position to move fast with the barrels along the value chain if successful exploration. We are in a good position when it comes to data. We also have to admit that the most easy oil and gas in Norway have been discovered. This really means that we have to be more innovative. We are building a strong organization where continuous learning is key, in fact, to reveal the full potential in our asset and to create also new core areas with potential production. We prioritize some key areas. Play innovation means to improve our understanding of the subsurface potential in already proven plays. Secondly, to look into not explored plays, just to understand those better and to work them more out on the shelf. This is all about people having the competence and the experience needed.
Digitalization, including integration of all types of petroleum technical data and machine learning analytics will be an important part of this. However, I also say that we need access to much more data to really significantly improve our prediction and thereby also reduce the geological risk to define new drilling targets. In addition, we are building an internal competence center on seismic processing and imaging capacity, creating a competitive edge to increase value creation in the company. This way of working gives us a better chance picking the best opportunities simply because we have the best data sets. The price can be high when finding more resources being fed into the company's producing assets or finding high impact discoveries, creating standalone developments. We have also established a collaboration with the academia and discussed with vendor to establish an alliance, working together, sharing data, software, competence, and technology.
The production on the NCS is quite interesting to see this figure. It's declining fast after 2025. To keep the production at this level, we have to prove up significantly higher volume to establish new infrastructure on the shelf. I can also be honest, but except from Johan Sverdrup and Ormen Lange discoveries, there haven't been added much more resources from impact discoveries since 1994 and up till now. After 2025, we are also much more dependent on yet-to-find resources to keep the production. The NPD confirmed that the yet-to-find and the understanding are that about two-thirds of these resources are in the Barents Sea, and most in the Barents Sea North and Northeast, which are not yet opened up for petroleum activity.
The industry have, however, collaborated to actively reduce the cost, and we have also worked it within our alliances in project and drilling well. New projects are being sanctioned now far away, breakeven of $35 U.S. per barrel. The NCS is very competitive on cost, compared to U.S. shale oil and also deepwater. NCS is also, when you look at this perspective, less hit by global peak oil demand than U.S. shale oil compared to the different Paris Climate scenarios. However, the NCS is not so competitive on finding new high-impact volumes based upon the last 20 years exploration. There were, in addition, fewer companies applying in the 24 licenses round than in the previous round when the Barents Sea Southeast was opened up for the industry.
In fact, and I'm aware of that it's a new government and there is a new agreement, platform of agreement for new government, and it also comes to open up of new areas, or to say that it's postponed at least until 2021. I believe that the time is now to start this process, because to open up new areas for the petroleum industry and for exploration, takes time because of different democratic processes to be clarified before making the final decision by the parliament. If Norway want to be a strong energy provider into a global energy mix in a long-term perspective, it is important, in fact, to have this on the agenda, as long as we have the competence and the capacity and also the infrastructure to further develop the petroleum industry.
The company today are well positioned in all three basins on the NCS, and approximately two-third of our licenses are in the North Sea, where we have four producing assets. In the Barents Sea, we have solely exploration licenses, and our activities are mainly on the Loppa High North and South and in the Barents Sea Southeast. We have, in addition, secured a solid exploration position in the Norwegian Sea around the Skarv producing assets and along the Nordland ridge. This year, our exploration program is skewed towards frontier wells. More than half of the wells will be drilled in the northern areas, one in the Norwegian Sea and six wells in the Barents Sea. The remaining wells will be drilled in the North Sea.
We have also seen a positive development, as also have been shown you earlier today, on the cost level in the industry during the last couple of years. Exploration cost is also significantly reduced, and average well cost was last year $240 million U.S., half the price of an exploration well in 2013 and 2014. Further, the company, with us, our sanctions development project at a breakeven price lower than $24 U.S. per barrel. In the areas being largely unexplored, the accumulation of hydrocarbons are not always big enough. Now I'm thinking about Barents Sea and part of the Norwegian Sea. They are not enough for standalone development. However, we are working on concept which can also increase the influence of development of smaller discoveries in more remote areas to create commercial production and production hubs.
This approach will also reduce lead time from discovery to production and create higher value. Last year, there was an exploration drilling record in the Barents Sea with 17 wells, which was half of the total wells drilled on the shelf. 11 discoveries total in Norway, or where 6 discoveries were made in the Barents Sea. Two of the discovery, Filicudi, the largest one, where we were participated, and the Kayak discovery, both smaller discoveries. None of them represent standalone development. But both are close to infrastructure, at least when Johan Castberg is on stream. In spite of few commercial discoveries last year in the Barents Sea, we also see here that the Barents Sea is still above global exploration average, both on success rates and volume per well.
The resource addition totally on the NCS was last year between 157 million barrels of oil equivalent to 377 million barrel equivalents. None of these represent standalone developments. My view is that it would also have been crucial for us as an industry and a company to get access to the data gathered by the NPD the last years from the Barents Sea North and Northeast. This shows significant volume potential in the F5 numbers. All this data and information could also be of interest to enhance our understanding really of the remaining potential in the Barents Sea. I mean within the Barents Sea, which has already been opened. Also especially since the last year's drilling campaign was so disappointing. We can also ask ourselves if we really also have understood what the code we should use to further explore the Barents Sea.
However, we are excited about our drilling campaign in the northern area this year. Kvitungen Tumler in the south, close to Skarv area, have an upside of 200 million barrels of oil equivalent. Anyway, given a discovery, it will be commercial because it's so close to Skarv. In the Barents Sea, a high impact well on the Svanefjell prospect with a shallow reservoir, which is driven by geophysical observation will be drilled. The hydrocarbon case is a question. Given oil and success, this could open up for a new development east of the Loppa High South. There are, in addition, more prospects in the vicinity which could make a development even more robust. Stangnestind, and then we move to the Barents Sea Southeast, will be drilled second half of the year.
The targets where we are exploring for are within a mega closure and a new petroleum province where there still are many questions. After also some disappointing result on Korpfjell last year. The well will, however, give important information about the potential within such a mega closure, both on the petroleum system, reservoir presence, and qualities, and volumes. Two licenses have also been awarded on the other side of the borderline within the same mega closure, and that license at least postulate really high volumes. The mega closure is called the Fedynsky High, whereas Rosneft and Eni are partners with a common exploration program. I think we should not forget where we are partner either. We are a partner in four other exciting wells in the Barents Sea, concentrated on Loppa North, and also in the Barents Sea Southeast.
We are the one company participating in all new plays to be tested this year, which will give us valuable information to deeper understand the potential for making also more discoveries in this region. All the partner-operated wells are on the high impact side opportunities, but also with high risk. Gjøkåsen in the Barents Sea Southeast, south of the Stangnestind, where Statoil is operator, has the highest volume potential upside. Exploration. We're going to the south and the North Sea. We contribute strongly also to increase the value of existing fields by finding smaller accumulation around assets. We have invested in high quality seismic data both in Valhall, Ula, and Hod area, as well as we have in Alvheim, where we have reprocessed approximately 4,000 square kilometers of 3D seismic data of different vintages to enhance the data quality.
One of the drilling candidates based upon this data is the Trost well being drilled now. These infill tie-backs have shown to deliver excellent production with Viper and Kobra, and payback of investment in a very short time. Cassidy in the Ula area has been matured and approved as a drilling candidate, and Hod appraisal will be of importance for the Hod redevelopment project. In addition, we are exploring also for creating new potential production hubs in the northern part of the North Sea with also the Ravåsen well. If this well is a success, there are a follow-up potential in the area. In the Sleipner area, we have defined some prospects. We have defined some prospects, and made one drilling decision on Horne, with an interesting upside volume potential, and this is most likely a tie-in to Ivar Aasen, given success.
I'm also proud of the organization, which have enhanced the understanding of hydrocarbon migration based on certain type of data and observations. This is a possible new APA 2017 license, which we have applied for. They have done some detailed interpretation to define also the trapping mechanism. This prospect has still, of course, a geological risk, but given success, it has the potential standalone in a very mature province. We are planning to drill this prospect this year if we become the operator of the new license. I think we will know tomorrow evening because there is an award session of the APA 2017 at the Sandefjord Conference. I'm really excited to start planning for this well, testing this opportunity with a high potential.
It is important to continue to keep the exploration cost low and explore around the producing assets, since exploration successes contribute to keep the production level or at least arrest the decline for a longer time. The timing for finding more volumes is now in also the Ula Valhall area. That is why we also have invested in new high-quality 3D seismic data to make a unified data set available for evaluation and also try to vacuum for new opportunities and drilling candidates. Our experience is that even minor discoveries create high values in such an area, and we are working this area in close cooperation with the asset owner and the subsurface people in the asset. Finally, this shows the 12 wells with the volume potential and ownership share where we are operator and partner this year. It shows a tentative drilling schedule.
NPD anticipated approximately the same number of exploration well this year as last year, 34 last year, which means that we are part of approximately one-third of all the exploration wells being drilled this year in Norway. It is a really exciting drilling program with the potential to deliver significant resources net to Aker BP. If some of the infrastructure wells deliver, it will also create high-value barrels, and the impact wells have the potential to create new producing hubs, but also have higher geological risk. 2018 is another exciting exploration year. Thank you for the attention. I give the floor to Alexander.
Thank you, Gro. Good afternoon, everyone. Thanks for everyone for still sticking around. You are on the final stretch now. In my section, I will initially give some perspectives on how we think about funding of our business. In the second part of my presentation, I will provide some guidance on some of our key 2018 figures. Our funding strategy has remained firm for a couple of years now, in which we seek to diversify our capital structure to attract both banks and bond investors to have as low cost of capital as possible, while at the same time to have a structure and a liquidity buffer that allows the company flexibility to grow further. As expected, 2017 was an active year for us at Aker BP, also on the financing side.
We put in place an amended bank facility that very much increases flexibility and predictability, at the same time reduced our cost of debt. Also, during the warmer months of the year, we obtained credit ratings from Standard & Poor's and Moody's, subsequently, we raised $400 million in the international bond markets. These credit reports are readily available on our website. Thirdly, we raised $500 million and $1.5 billion in the new bank facility upon acquiring Hess Norge. 2017 was a year where we again saw fantastic support from our banks, bond investors and shareholders. We kick off 2017 with a really robust balance sheet and strong cash flow generation that allows us to increase the dividend level. Our debt structure consists of a mix of bank and bond debt, both secured and unsecured.
The main source of debt funding for the last few years has been our reserve-based facility. Today, it stands at $4 billion. Availability under the RBL is calculated on a dollar per barrel multiple, it's based on our certified reserves. The full $4 billion was available at the end of the third quarter. Now, with the additional Valhall reserves stemming from the Hess acquisition, we would have a calculated borrowing base far in excess of these $4 billion currently committed capacity. At the end of 2017, we had drawn less than one-third of that available amount. After the acquisition of Hess Norge AS last year, we signed a bank term loan agreement of $1.5 billion, which has a pledge in the shares in Hess Norge.
The loan matures in 2019, but as we expect to settle the tax losses in Hess Norge during 2018, this loan will be repaid at such settlement. In addition to the bank financing, we have two unsecured bond loans. It's the 1.9 billion NOK DETNOR02 bond that matures in 2020, and it's the $400 million bond that was placed using the U.S. documentation last year. Based on these drawn amounts, we have a pre-tax cost of debt of 4% and post-tax of around 2%. Now, as you might expect, we will continue to actively manage this debt portfolio going forward. Many, if not all of you, will have heard me talk about the tax system on the Norwegian Continental Shelf before. It is a unique fiscal system, and I keep reiterating the key features because it's fundamental to how we think about funding of our business.
We believe it's equally important for investors to understand the downside protection in this system. We only operate in Norway, and we are happy to see that the fiscal regime in Norway continues to be predictable and supportive to companies like Aker BP that are willing to invest capital into new projects. Our preliminary year-end 2017 net interest-bearing debt was $3.2 billion. However, when we compare this to the tax value of the non-depreciated tax balances of $2 billion and the tax loss that we acquired with the Hess transaction of $1.5, and we add back the estimated tax payable related to our 2017 activities, we have a tax-adjusted net cash position of $200 million. Our hedging policies are unchanged, and we continue to closely monitor the company's financial risk profile, and we utilize various hedging mechanisms to protect downside.
We've hedged about 20% of our 2018 oil production by acquiring $50, then $55, and now $60 puts, and we may acquire another 10% within our hedging policy. We will likely start to acquire 2019 puts soon as well. Following the merger with BP Norge, we have renewed all insurance policies. Due to favorable market conditions, we were able to achieve improved terms while reducing premiums. Among several improvements, our loss of production insurance will now kick in after 45 days instead of 60 days. Let's move to the 2018 guidance. I will cover the 2017 actuals in our Q4 presentation in just a couple of weeks. We are expecting 2018 production to be between 155,000 and 160,000 barrels of oil equivalent per day, which should also this year be around 80% in liquids. Production cost is expected to be around $12 per barrel.
This is higher than the revised guidance for 2017, mainly as a result of volumes from the Valhall area, representing a higher share of total production following increased ownership in Valhall and Hod. 2018 CapEx is expected to be $1.3 billion. Cash spent on exploration and decommissioning costs both are expected to be around $350 million. Thus, we expect investments of about $2 billion in 2018, a significant increase from 2017, as we have a number of projects that are moving into the execution phase. I'll now spend a bit of time to go through each of these in some detail. As mentioned, we're estimating a production in 2018 between 155,000 and 160,000 barrels of oil equivalent per day. Production from the Alvheim area is expected to amount to about one-third of total production at a production cost just below $6 per barrel.
The unit cost is expected to increase from 2017, as the production last year was very strong once Viper and Kobra commenced production. Ivar Aasen and Skarv combined is expected to account for about one-third of 2018 production, with a production cost of about $9 and $12 respectively. Production costs for the Valhall area is expected to be in line with the level seen in 2017, at around $18 per barrel, but volumes net to Aker BP will increase significantly, reflecting the new ownership share. Production cost at Ula is still the highest across our portfolio in 2018, but I am pleased to see that we expect around $30 per barrel in OpEx, improved from the $40 per barrel we saw last year. Main reason here being that the new Tambar wells are coming on stream this year.
With the current portfolio, our long-term target is to have a production cost across this portfolio of less than $7 per barrel. We believe this can be achieved by delivering on the improvements agenda that Per Harald walked you through, but also by bringing new profitable fields on stream. We are increasing our CapEx spend year-on-year with about 40% to $1.3 billion. In 2018, we have numerous projects ongoing, and the largest part of the spend is related to Valhall, where we now have 90% of the equity, and on Sverdrup, where 2017, last year, and 2018, this year, will be the peak investment years at Sverdrup. We will continue the drilling program from the IP platform that Karl talked about, and we expect to drill three wells in 2018 as part of this.
We will also plan to drill one well at the Valhall Flank North Water Injection late in the year, and the Valhall Flank West project, which was sanctioned in December 2017. The 2018 activities here, they include the detailed engineering and startup of construction. In the Alvheim area, the investments in 2018 mainly relate to drilling of the Kameleon Infill South well, should be around Q3. The Volund sidetrack North should commence after that in Q4. We will have the construction of subsea systems, flow lines for the Skogul project that was also sanctioned in December 2017. In the Ula area, we continue the Tambar and Oda developments, which make up the bulk of this investments in this area. In addition, we have a power project going on at Ula, as well as several smaller projects in order to prolong the field life there.
In the Skarv area, the Århull development is underway. The 2018 activities here, they include fabrication of subsea production systems, control cables, and flow lines. CapEx for this project is going to increase in 2019 when we get closer to first gas. Finally, at Ivar Aasen, there is going to be drilling of two water injectors and the Hanz appraisal well. Those will be the main activities next year. While the other category here includes IT and other corporate costs. Moving on to exploration and decommissioning. As Gro alluded to earlier, we have an extensive exploration program lined up for 2018. We are budgeting for a pre-tax exploration spend of about $350 million. Almost half of this spend is related to wells and testing for our 12-well drilling program.
Other exploration spend is related to field evaluation costs, primarily for the NOAKA area and Hod redevelopment and seismic acquisition on and near our existing acreage. In addition, we have, as always, other G&G costs and area fees for our existing license portfolio. As for decommissioning spend in 2018, our full-year pre-tax guidance is also around $350 million. This is almost entirely related to the P&A campaign going on at Valhall, where the Maersk Invincible rig will run continuously throughout the year, compared to just eight months in 2017. When we put all of these estimates together, we get a picture of how operational cash flow will look like in 2018. The table here is based on the midpoint of our guiding ranges on production, on CapEx, on OpEx, and decommissioning costs. 2018 cash cost before taxes is estimated at around $16 per barrel.
This is made up of production costs of $12, other OpEx a little less than $1, and finance costs of around $3 per barrel. That is assuming the net debt levels at the end of 2017. This means that we generate positive operating cash flow, excluding any working capital changes, as low as $16 per barrel. Tax payments this year is expected to be net positive due to the Hess Norge tax loss. We plan total investments in CapEx, exploration, and decommissioning expenses of about $2 billion. This amount to $35 per barrel, if you compare that to the estimated 2018 production. Free cash flow before dividends thus breaks even in 2018 at a realized hydrocarbon price of $29 per barrel. This concludes my finance section. I will leave you with Karl for some concluding remarks. Thank you.
Thank you. Good. Hope you saw a little bit of our exploration program. I'm really happy I was able to demonstrate my point that the cash flow generation in the company is extremely strong, even in a low oil price environment. If we go back to the investment case, I think you'll see that there is consistency across our set of activities, whether they're linked to execution of existing programs, wells, or projects. They're linked to our activity program, as Per Harald demonstrated, but with the focus on digital and a focus on alliances, or they are linked to quite an exciting exploration program in 2017-2018. It's a stretch if you had told me a couple of years ago that we would be a third of the activity on exploration in 2018.
I think in summary, it consistently demonstrate that this company has built superior shareholder value in the last three years. The strategy is firm, what has worked as a success case in the previous three years will continue to be the guidelines of this management in the years to come. I still believe there's a lot of upside to be had in the improvement program. Even if we have been surprised by the effect it had so far, we still haven't been even close to realizing the full potential. Finally, we've, over the last couple of years, and particularly last year, been able to build an even stronger platform for further organic growth across the entire portfolio. What is going to be our priorities going forward?
We are going to continue to focus on safe and efficient operation, the same manner of relentless focus that we've had so far. We are going to focus on excellent project delivery, making sure that we connect all the dots and really put a lot of energy behind that. I think so far we've demonstrated that Aker BP is able to execute large, complex projects with high quality and high flow efficiency. We are going to keep on focusing on our improvement program with even more energy and even more focus, particularly on digitalization and reorganization of the value chains, as we see those as interlinked and primary drivers to our value creation, but without forgetting that you cannot digitalize on flow efficient operations.
Continued also on the Lean program, we are also very proud of our colleagues that are able to execute these projects in a flexible and efficient manner. We are going to continue to mature and feed in projects into the hopper, the benchmark of 35 still is there. Although we see that this benchmark may have to be pushed down as more of the improvement programs takes effect. Finally, we've been really strong on maximizing the resource base in our existing assets. We are continued to put that as a high priority going forward as we see it create significant value, both in terms of unit cost but also in terms of growth potential. Of course, last but not least, we are going to selectively pursue inorganic growth opportunities as they appear, and we feel that they are value accretive to our shareholders.
In sum, I hope you get some more insight. It's a long day, I know. Some more insight into Aker BP, what we are about, and how we are generating value. We'll round off the day by a Q&A session. I'll ask my colleagues back on stage, that includes you, Per Harald as well, to answer any questions that you may have. There might also be some questions on the net.
Amy Wong from UBS. A question on your target to achieve the $7 U.S. dollar per barrel production cost. Can you put a bit of timing on when you expect to achieve that? A follow-on to that would be, if you were to split that achieve reduction between the different buckets, which is digitalization, lean operations, strategic alliances, how much do you think would you allocate to the various factors in terms of achieving that cost reduction, please? Thank you.
Okay. Sounds like I have to answer that. Well, first of all, we haven't really set a timeline. It's also quite interesting because, as I said, we are increasing significantly the MMO scope in our operations as we're pushing down scope. I said that we had increased the number of hours since 2016 by 40%. A lot of this has actually entered into the OpEx. The underlying OpEx, if you remove the scope increase, would probably show a much better trend than what Alexander has demonstrated. We still feel it's fair to show the real value as you can observe them in the finances. I think on different track on different fields. Skarv will probably come there in the, I would guess, 2019, 2020 on the current path that they have now.
For some of these other fields, it's much more difficult, like Ula and parts of Valhall, which would have huge fixed cost base, and will need massive amounts of production injection to generate that. The reason we've set that out is predominantly to provide a very, very hard target. Now, if you asked how are we going to attain that, I would probably put 50/50 between alliances or one-third between alliances, lean, and digitalization. They're actually all connected. You probably won't be able to achieve your target in digitalization if you haven't been able to create flow efficient work procedures. At the same time, you probably won't be able to get full benefit out of the alliance mechanisms without a digital way of collaboration in a flow efficient manner. That will change from asset to asset.
Valhall will have more effect of lean simply because the number of hours that goes across that platform is bigger. While Ivar Aasen, for example, with a lower number of hours would probably have bigger effect of digitalization. Sorry for the bit unprecise answer.
Hi there. David Mercer, Deutsche Bank. Thanks, kindly take my questions. I suppose first on exploration. Talked a lot about what you'd be doing next year and how this year was disappointing. I suppose specifically on your South Loppa this year, there was a lot of expectation on Hurri and Hufsa. We were told they were on trend, they were analogous. Just to give us an idea of what went wrong and how you think you can improve on that next year. Secondly, on the CapEx, I suppose. Thanks for the 2018 guidance. Can you give us a bit of guidance on run rate going forward? At your current equity positions under your current PDOs, should I expect $2 billion for the next few years? You said you'll be finishing up on your Valhall abandonment expenses about Q4. Does that mean the Abex is going down in 2019?
I suppose just lastly on the cash taxes. Thanks. I suppose it's just the way they seem to go up by NOK four each, 60 to 70 to 80 that I don't quite understand why if you're earning NOK 10 more revenue and you're paying tax at 70, are you not paying NOK seven tax for the differential?
Okay. Good. I think Gro, you can answer the exploration one.
I'll start with the Hufsa and Hurri, those prospects. Of course, they are very interesting. High volumes, but also have high risk. I believe that for the Hufsa, which is to the south, it's more in the migration shadow than what we expected. When it comes to Hurri, also large volumes and could really do a difference to a development in that area if it had succeeded. It's more about the leakage. That is in a way a short explanation of why we failed on those two wells. Of course, they had to be drilled. They're so high volume potential. I think the only thing was to drill them and to test out what the potential could be. When it came to Gohta and the appraisal well, Gohta is a carbonate reservoir. It's kind of difficult.
We have 2 types of reservoirs there, conglomerates, and which can deliver well. Here we were in the carbonates, and we had some challenges with the reservoir quality. It could be, to be honest, if we had evaluated it even deeper, because we saw we had some loss in the well, it could be that we could have tried to test it. This is, in a way, it's a kind of learning, and we still have something to learn when it comes to carbonates and operate those on the Norwegian Continental Shelf.
Okay. On CapEx and tax.
I suppose I have to start with tax, as that's my favorite.
Yeah.
I think it's a bit of a coincidence, David. It's a mix of various factors. The starting point is that I think it's NOK 4 will be payable whatever the oil price is because it's based off of This is cash taxes for this year, so it's from the taxable result from 2017. That's the floor in any case, so it doesn't matter. It's a mix between the tax regimes. We have two tax regimes, and it depends on how much is taxed in each and how each of the CapEx is deductible in both of them. That skews the picture on that as well. I think if we had a higher oil price, you'd see it wouldn't be NOK 4 on each of them. On CapEx, you should probably expect abandonment to go a bit down from this year's $ 350 million.
Exploration budget is a bit hard to tell. It depends on which wells are mature enough and which are approved. The $ 350 million, whether it's higher or lower, it's a bit difficult to judge. On the CapEx, that would obviously depend a bit on some of the solutions and timing of the now PDO-approved projects. It's hard to put a specific number on that, David, but perhaps not too far away from where we are in 2018.
Certainly with the higher production going forward, it just means a slightly higher run rate in CapEx.
Do keep in mind that this is the peak year for you on Sverdrup, right? Last year and this year. That tailors off, but then some of the other projects, in order to get to 330, if you want to get there, it will be some years with higher CapEx. It depends a bit on timing on, say, projects like NOAKA, for instance. That's going to impact whether it's 2019 or 2020 where that CapEx will kick in severely.
I think it's actually also interesting when you assess the CapEx run rate going forward, is to assess the economic effect that CapEx will have on your business case. What we've seen as the SD CapEx has gone up, but the break-even has gone down, the cash regeneration from the investment of that capital has gone up significantly. As Alexander also demonstrated, one of the unique features with the Norwegian fiscal regime is the downside protection. This is exactly what you want to see of an oil and gas company in Norway. You want to see increasing production, you want to see high cash flow out of existing production, and you want to see an investment in low break-even projects that increase the resource base.
In many ways, we've been able to generate an investment case that is almost ideally suited to the Norwegian fiscal regime.
Halvor Sivertsen from SEB. When in 2018 are you expecting the Hess tax to be settled? Is that during summer or during winter?
Second half of next year. Whether it's during the warmer months again, like we saw with the BP, or if it will be in the fourth quarter, it's a bit too early to say. Second half of next year.
On the dividend, both the level and the growth ambition of $100 a year, what should it take for you to change that, either up or down, in terms of the market that you expect?
What should it take? Well, as you know, Halvor, there's just so many things going into that equation, you may be naturally thinking about oil price. What does that take? I think we have many levers to pull if it's CapEx or if it's other, or if it's ensuring a lot through buying put options. For us, it's more the totality and the robustness that we see, which I'm sure we will evaluate going forward. We believe, given where the portfolio is sitting today, how we see the outlook today, putting that number and putting that ambition in, we feel that's a robust case the way we see it. Not the precise answer you were looking for, I suppose, but it really is a view of the robustness of the totality here.
All right. Lastly, on exploration, the Stangnestind prospect, it's a mega closure. Can you say something about the prospective resources?
We have the resources back in the overview there. I think it's a big uncertainty there, to be honest, because it's an unexplored area. What we know from the Russian side is that they have 18 billion barrels of oil equivalents on the Russian side. The high is a bit smaller on the Norwegian side. We have also thought about where to place the well so that it could be a simple way also to commercialize the volumes in Norway. Of course, if we deliver on this deepest target, then it could have a much bigger upside there. There is high risk.
[Thank you.]
Karl-Fredrik Svedberg from ABG Sundal Collier. First of all, last year you exceeded your production guidance by a healthy margin. I was just wondering, would you say that there is upside or downside to your guidance this year? Then following, last year, we saw that you were partnering with Lundin Petroleum on quite a few wells, where they were operating. Is there any reason why you've taken more wells as operator this year?
Okay. When it comes to the production guidance, I think the effect that you see on the production guidance is basically almost the same effect as we've seen on breakeven. It's an effect of the continuous improvement program that's been running in the organization. Of course, it's easy to extrapolate and say, well, we'll have the same kind of improvement program also in 2018. Therefore, the guidance is conservative. What we've done this year is we made an assessment of what is a likely effect of that improvement program in 2018. As you can see, it's quite a narrow margin from 155 to 160, and that should give you a little bit of confidence that at least from a management perspective, we believe this to be an expectancy correct estimate.
Of course, I can promise you we're going to work as hard as we possibly can to make sure that is the low end of the spectrum. That's the kind of the balance. We'd love to give you a good answer. We'd also love to make sure that we continually improve and beat our own expectations. When it comes to the exploration program, this is probably more an effect of the work that we've been doing the last three years, where we've been high-grading the portfolio, both by aggressive application in the APA and license rounds, also by a series of BD transactions. It's a little bit of a coincidence that we end up with 12 wells this year and the distribution we do.
That being said, when we put that into the business plan and the long range, this is a pretty much an optimal portfolio for us to drill in 2018 in terms of capacity across the hubs, drilling capability, and timing related to early-phase projects. There's been a little bit of an adjustment. It wasn't a conscious strategy last year to end up with that many Lundin-operated wells. This year it's much more driven by the ability to generate value across our hubs.
Okay. One more quick question. You've been talking about M&A. Are you looking to do any asset transactions, for example, rig or other types of assets that you would use in your operations? Or would you rely on vendors for doing those or being the asset owners?
Well, we're always looking for the most efficient way of generating the necessary services. So far, we've come to the conclusion that the most efficient way is to enter into alliance with service companies who have done this repeatedly rather than trying to replicate it as a one-off. I'll say that that'll probably be the main strategy also in 2018 and 2019 and going forward, but I won't exclude that there won't be singular events where we see an opportunity or a need to change that strategy.
Thank you.
Yeah. A few follow-ups from myself, Anders Holte at Danske Bank. First on NOAKA, as it's now known as. Did I hear right in saying that you're aiming for concept selection by Q1 2018? Right. Then Statoil has previously been talking up this project and saying this will be one of the first real digitized projects, and they see rather substantial cost savings. Do you share that kind of view that this will be one of the first new projects, to call it that way, from the industry? Lastly, on Valhall, just when we look, if we just exclude the west flank, the IP drilling, and the north water injection project, will that keep on going now for a couple of years, or is this the last year where that will run?
Okay. Well, if you just start with the NOAKA project, I think there's several possibilities that are assessed. It's NOA standalone. It's Aker BP standalone. It's an area solution. My statement is, and our stand is that we need to put in place a solution that maximizes resource utilization in the area. Yes, I believe that Aker's development solution, such as proposed by Aker BP, will create a lot of competitiveness in the vendor industry by introducing new project execution methods, new digital ways of working together. The PUSH project that Per Harald talked about has demonstrated that it's possible to improve these processes significantly. Of course, we'd love to invite the industry into such a project as we believe that will increase the competitiveness of the Norwegian vendor industry at large. Then your last question on, remind me again on that.
It's just on Valhall, on the IP drilling program and the water injection north. Those two projects, will they run its course?
Uh, the-
Will they run later this year or?
Yeah. The way I see that currently they will run its course. We're currently also working hard to add additional infill targets on Valhall to the existing drilling program to avoid a start and stop that you often see on these kind of installations. As you also probably acknowledged from the presentation, following the stop of the P&A program in the back end of 2018, we'll have a lot of available drilling capacity from the Maersk Invincible, which will then be utilized on the north flank. We're also maturing targets in the south flank as we learned that these improvement programs accelerate faster than we planned. To have more drilling targets planned so that we avoid white space in the drilling schedule.
Thank you.
We'll take a question from the web. It's from Alvin Thomas at ExxonMobil. Do you believe the efficiencies and cost improvements are deflationary for the oil price in the medium term? As a result, what oil price assumptions do you plan out of?
Well, to the first question, the short answer is no. I believe that it's hard to see a lot of other companies driving the same kind of changes that you've seen in Aker BP. As a market, as a whole, there's of course a reduction, but you don't really see a necessary uptick in investment as a cause of that reduction in input factors. I don't believe that you'll have a deflation or deflation drive on the oil price. As it comes to the planning, we haven't really been out there communicating that.
We haven't communicated that, but looking at other industry sources and companies disclosing oil price assumptions, I wouldn't say we're very much different from others.
I don't think that's what differentiating us is our aggressiveness on our price planning assumptions.
Okay, no more questions then we'll conclude with the Q&A session and today's program. Thank you everyone for showing up.
Thank you.