Good morning, ladies and gentlemen, and welcome to Statoil's Capital Markets update on what I know is a very busy day for you all. I'm very pleased that we will be able to run you through a series of presentations to look through our outlook over the next four years and also comment on the quarter results that you've seen presented this morning. We'll be starting with presentations from Eldar Sætre, our CEO, Hans Jakob Hegge, our CFO, Margareth Øvrum, EVP for Technology Projects and Development, and Torgrim Reitan, EVP for DP USA. I'm delighted that we have many members of the executive committee here who will also be able to answer questions both in the session itself and after the session, more informally in the gathering area outside.
Safety is central to everything that we do in Statoil. With that in mind, I'd like to just read a very short announcement about safety specifically for today. If an emergency situation should occur while we are here, the evacuation signal is a voice system announcement. Please note, we only evacuate the building should the voice announcement say to do so. Then please use the signposted fire exits within the venue. Follow the signs and messages from the guards. Exiting is at ground level and the assembly point is situated on Bartholomew Close. With that, I'd like to move directly into the capital markets update itself, and I'd ask Eldar to join us on stage. Thank you very much.
Thank you, Peter, and good morning, everyone. It's great to see you all. This is the third time that I have the pleasure of welcoming you to our capital markets update here in London. It is the first time I do so without looking back at yet another year of falling oil prices. Let's make that a new tradition. 2016 was a challenging year for the industry. A fact also reflected in the fourth quarter and full year results for Statoil, which Hans Jakob will get back to soon. There is also a saying that you should never waste a good crisis. I'm proud to say that Statoil is emerging from this downturn as a stronger and much more competitive company. We have reset our cost base.
We have transformed our opportunity set and sharpened our strategy to be even more value-driven in everything that we do. In short, we are now well-positioned to capitalize on the opportunities of a world-class portfolio. Last year, we achieved a lot, but we also experienced the worst thinkable. We had one contractor fatality during construction work in South Korea, and on the 29th of April, we lost 13 of our colleagues when a helicopter crashed on its way to Bergen. For the year as a whole, our serious incident frequency came at 0.8, which is an increase from the two previous years. I'm not satisfied with this development. Over many years, we have improved our safety results, and now we have to get back on a positive trend, and we are fully committed to doing so.
We have already taken several steps to reinforce safety measures throughout our company, and it starts with me and all our leaders being crystal clear that safety of our people and the integrity of our assets and operations is and remains our top priority. I take pride in the fact that we have a track record for delivering. We promised $2.5 billion in yearly efficiency gains by the end of 2016. We delivered $3.2 billion. Since 2013, we have taken down operating costs and SG&A by 30%. The break-even price for what I like to call our next generation portfolio is now at $27 per barrel.
CapEx for 2016 came in at around $10 billion, well below the initially guided $13 billion, mainly due to increased efficiency, strict prioritization, and also a very disciplined project management, project execution. We sanctioned five new upstream projects last year and 1 in offshore wind and added 1 billion barrels of resources to this portfolio. Looking at the energy markets, we see still both the traditional commodity cyclicality as well as longer-term structural changes. The oil price is clearly showing signs of recovery on the back of expectations of a tighter market balance and also the recent OPEC agreement. We expect oil prices to rise towards the level of $75 by 2020. But we also see significant uncertainty and continued volatility.
In addition to OPEC policies and discipline, how much and how quickly the U.S. onshore response is one of the key questions, obviously, in this equation. When it comes to natural gas, short-term prices are under some pressure. Medium to longer term, however, we see a stronger gas market emerging. Declining European production, indigenous production, markets gradually absorbing new LNG capacity and clearer policies, reflecting the need for natural gas to replace coal in power generation. All these components support this view. Jens will give you more details, a more detailed outlook at our gas seminar in London in four weeks time. Looking then towards 2040, we see an energy system in transition. New renewable energy is rapidly becoming more competitive and will continue to be the fastest-growing source for new power generation.
Technology and innovation are driving this development, and we do not expect this to slow down, despite some uncertainties on international cooperation and also global climate policies. Still, in 2040, significant new capacity will be needed to meet demand for both oil and gas, regardless of which energy scenario you tend to believe in. The winners will be the producers that can produce and deliver at low cost and with low carbon emissions. High value, low carbon is also the core of our sharpened strategy. We will shape our future portfolio guided by a set of strategic, call it principles. The first one is about cash generation at all times. To me, this downturn has truly demonstrated the value of resilient cash flows from our operations. Sufficient cash generating capacity, also in a low price environment, is critical to secure a financially robust future.
You can call it the low-cost strategy for high value. The last few years have also underscored the importance of the Norwegian Continental Shelf to us in this respect. As a large operator, we have been able to effectively implement significant cost improvements across the entire NCS portfolio, bringing operating costs down to an impressive ten-year low and increasing production efficiency consistently by 67, 6.5 percentage points, adding around 75,000 barrels per day, almost for free. CapEx flexibility is the second guiding principle for us. Thanks to the efficiency program, a high share of operated assets, and also our position in the U.S. onshore, Statoil was able to reduce organic CapEx by 50% over two years, while also increasing our production capacity.
The flexibility to adjust spending when you want to do it and not when you have to do it is highly valuable, supporting our financial management and increasing our capacity to create value through the cycles. Torgrim will give you a more detailed update on our progress in the U.S. later today. Thirdly, we remain a cyclical industry, and this offers opportunities to create value for companies with the capacity to act counter-cyclically, and I will revert to this point soon in my presentation. Finally, as we move towards a low carbon future, carbon intensity and efficiency will increasingly be a competitive advantage. Our emissions per barrel is around half of the global average, and carbon efficiency will also be a factor for us when shaping our future portfolio.
Statoil will develop our business supporting the ambitions of the Paris Agreement, and we are proud to be ranked number one in our industry on carbon resilience by the Carbon Disclosure Project. As I will get back to, we are also building a profitable business within renewable energy. Let me then turn to our improvement efforts. Our target for cost improvements by 2016 was annual efficiency gain of $2.5 billion measured against 2013. We delivered $3.2 billion. This is a total reset of our cost base. We are not done improving. In fact, we are already chasing the next $1 billion. On top of the 3.2, we will get further impacts from already initiated improvements and market effects, and that is in particular related to project developments.
The next phase for us is to go from an improvement program or project mode to a culture where we continuously improve, and we are well on our way. We are learning from other industries and using the full toolkit from the lean methodology and standardization to technology, innovation, and digitalization. In sum, this adds up to an additional ambition for 2017 of $1 billion. The question that we often get is how sticky these cost improvements will be when markets recover and the heat of this industry, we've seen it before, is turned back on. My response is that we will make them stick. We also believe there is a significant potential from simplification based on that standardization and based on that also industrialization related to our industry and our company.
80%-90% of the improvements that we have achieved are related to efficiency, doing things differently, not market effects nor deferring activities. As an example, we cannot control global rig rates, but we can control how long it takes to drill our wells. Now we get almost 70% more meters per day compared to 2013, 70%. These are real achievements, doing things differently, which will actually be even more worth in a potential future market with higher rates. Ladies and gentlemen, here we see our next generation portfolio. These are projects that were sanctioned since 2015 and plus non-sanctioned projects all to be in production by 2022. A portfolio with an average break-even price of $27 per barrel. It is truly a radical transformation.
In fact, during my 36 years now in Statoil, this is the most profitable opportunity set I've ever seen. While investments and breakevens are down, resources are up. We are looking at 3.2 billion barrels of oil equivalents in recoverable resources, and 65% of this is oil. By reworking solutions from all the way from the reservoirs to the markets, we are getting more for less. In 2019, we will see first oil from Johan Sverdrup, where the break-even price for phase one has been further reduced to below $20 per barrel. This has always been a world-class project, and now we have made it even better.
An impressive achievement, we are proud, and Margareth just can't wait to give you more details on this specific project, but she can also give you other examples of how we have improved in relation to other projects. For our post-2022 projects, we also see significant improvements, and we continue to bring down breakevens for this part of our portfolio as well. In a cyclical industry, timing matters. Between 2012 and 2014, we completed divestments of around $13 billion. This helped us in building a robust balance sheet, supporting our capacity to act counter-cyclically, also during the downturn. As one example, we have awarded $133 billion in contracts since 2015, capturing market effects, enhancing performance-based contract structures, and also offering obviously much-needed work to a hungry supplier industry.
On the exploration side, we added close to 25,000 square kilometers of acreage last year. We deepened our positions in prolific basins like Norway, the UK, Brazil, East Coast Canada, and added frontier options in countries like New Zealand, Mexico, and the Republic of Ireland. In 2017, this year, we plan to drill around 30 wells, including several high impact opportunities. That is seven more wells than we drilled last year while keeping spending at the same level of around $1.5 billion. Let's then look in somewhat more detail on how we are developing our new energy business. As an energy company, Statoil considers renewable energy as a fully integrated part of our business, of our strategy. Industrially, this is an opportunity to leverage our core competencies to create value in new areas.
The Dudgeon offshore project is a good example in the U.K. With 67 turbines being installed as we speak, it is really a challenge that plays to our strength in project execution, in logistics and marine operations and other areas. Financially, renewables offers an attractive risk-reward proposition. So far in our projects, we see a real returns in the range of 9%-11%. With costs coming down quickly, renewables are set to be cost competitive, especially in power generation. With subsidies gradually being phased out, developers increasingly need to take on market exposure, market risk. This will also have an impact on return expectation and the competitive landscape in this industry. Strategically, renewables diversifies our portfolio, adding longevity and also cash flow resilience.
To illustrate the long-term potential in new energy solutions, we are indicating a range of 15%-20% of our CapEx in 2030 to this area. The growth profile will be backloaded, starting from a yearly level of around $500 million last year and growing, assuming that we are able to access and mature sufficiently attractive and profitable opportunities. Looking at the broader portfolio, Statoil is pursuing a distinct and value-driven strategy. On the Norwegian continental shelf, we have a unique position, and we will leverage this position further to maximize value. As a major contributor to our next generation portfolio and with further exploration potential, the NCS remains the backbone of Statoil. In our international business, we will focus, we will deepen, and we will continue to explore.
Brazil is already a core area for us, having accessed the Carcará discovery last year on top of Peregrino, phase one, phase two, and Pão, and also building on our strategic partnership with Petrobras. In the U.S. We will continue to improve, to operate, and to add acreage to our highly flexible U.S. onshore position. In addition, our ambition is to add and to develop one to two core areas, both offshore and onshore, with the same long-term potential from further capitalizing on our legacy positions and through active exploration and business development. For midstream and marketing, the job is still to secure flow assurance by accessing premium markets, and also to increase value creation by strengthening our asset-backed trading based on a capital-light approach. Allow me then to summarize what you heard this morning. We have reset our cost base.
We have transformed our opportunity set for the future and continue to chase improvements, continuous improvements. We are ready to invest in our next-generation portfolio, currently at $27 per barrel, and we have the financial capacity to execute on this set of opportunities. With planned CapEx this year at around $11 billion, we will be cash flow positive at the $50 oil price. We remain committed to shareholder value creation and capital distribution. The board will propose to the AGM to maintain the dividend at $0.2201 per share in the fourth quarter, offering a scrip option through third quarter 2017, and maintaining share buybacks as a part of our toolbox. You should expect the dividend to be maintained at the same level for the first three quarters of 2017.
Finally, we are sharpening our strategy as an energy company towards 2030, being even more value-driven in everything we do. That's the core of who we are and how we are positioning Statoil to capitalize on high-value opportunities. Thank you very much for your attention. Now I leave the floor to Hans Jakob Hegge, our CFO.
Thank you, Eldar. Ladies and gentlemen, good morning. It's good to see you all. 2016 has been a tough year for the industry and for Statoil. The low prices have impacted our results. We have delivered solid operational performance, taken down costs, delivered $3.2 billion in annual efficiencies, and radically transformed our portfolio projects. At the same time, we have maintained financial flexibility and our firm commitment to capital distribution. We are in a strong position to capitalize on our high-value opportunity set. Let me start with our 2016 numbers. Impacted by the lower prices, we delivered adjusted earnings of $4.1 billion, down from $9.6 billion in 2015. Our net operating income was $80 million for the full year compared to $1.4 billion in 2015.
Heavily impacted by net impairments of $2.3 billion. This is mainly due to the changes in our long-term price assumptions. Still, we deliver a solid cash flow, which I will come back to. We delivered strong operational performance, high production efficiency, and increased our well capacity. Our production was above guiding despite the high turnaround activity. We deliver annual efficiency effects well above our ambition. OpEx, SG&A is reduced by 13% in 2016, and 30% from 2013. We have demonstrated strict financial discipline, improved the break-even our next-generation portfolio, and reduced organic CapEx for the year. In short, we are getting more for less as we have increased the production. Adjusted earnings for the group were $1.7 billion, down $100 million compared to the same quarter in 2015.
Achieved liquids prices increased by 14%. Gas prices were up in the U.S. and decreased by 14% in Europe. Our cash flow from operation was strong, up $1 billion compared to the same quarter last year. Losses in countries with limited tax shield gave an effective tax rate of 102%. Development and Production Norway delivered strong adjusted earnings of around $2 billion on par with the fourth quarter last year. Strong deliveries on production, operational performance, and cost contributed positively. OpEx SG&A is down 15% in underlying currency, and the regularity is at a record high level, well above 90%. Development and Production International delivered an adjusted pre-tax loss of $681 million. The negative result is impacted by expensed previously capitalized exploration, higher turnaround activity in Angola and Nigeria, and some quarter specific elements.
In the quarter, the cash flow from our international operations was around $17 per barrel after tax. This is the same level as from the Norwegian Continental Shelf. U.S. offshore production continues to grow. These are high-value barrels generating significant cash flow with low cash cost and no tax. Our midstream and downstream business deliver solid results driven by strong marketing and trading. Adjusted earnings were $514 million, up 22% from the same quarter last year. End of quarter, we had more volumes in transit to capture higher margins. During the quarter, we produced close to 2.1 million barrels per day, an increase of 2%. We are delivering a strong production for the full year, even with high turnaround activity, and we have increased both our total well capacity and the production efficiency.
Through the year, we have utilized the flexibility in our Norwegian gas machine and moved volumes out to periods with higher prices. In a year with limited contributions from exploration, we maintained our resource base above 20 billion barrels. Increased recovery rates contributed to our reserves, and the three-year average organic RRR was 90%. In 2017, this year has started well. Last week, we announced our second discovery. Two years after Valemon came on stream, we made a new gas discovery containing 20-50 million barrels, which can be put on stream immediately, adding considerable value. Our financial position remains robust with a strong positive cash flow of NOK 900 million in the quarter after tax payments, dividend, and organic investments.
The free cash flow for the full year was - $3.1 billion after net acquisitions of $1.1 billion. At just above $50 per barrel, we would have been cash flow neutral. Strict capital prioritization and efficiency improvements have reduced organic CapEx with $3 billion in 2016. The Coco payment, impairments, currency, and the increase in working capital gives a net debt ratio of 35.6%. The Scrip program has reduced the dividend paid in 2016 by $900 million, and the take-up rate for the shares issued in the quarter was 46%. We have delivered $3.2 billion in annual improvements. This is well above the increased ambition we outlined last year of $2.5 billion.
We have captured effects all across the dimensions we have been tracking since the start of the program. 80%-90% of the $3.2 billion is a result of efficiency gains and will have lasting effects. Let me explain the key elements behind these results. Close to a third, $1 billion, is within our unit production cost, where we already were a top-quartile performer compared to our peers. Costs are down, and production efficiency is up. Let me give you one example from Oseberg field center, one of the largest installations on the Norwegian shelf. From 2014, we have reduced costs by more than 30%. As we have prioritized strictly simplified processes and do more work ourselves, and the production efficiency is up from 85%-95%.
We have similar improvements across the portfolio with even tougher targets set for 2017. $900 million is the result of increased drilling efficiency. Since 2013, we have brought down the cost by $27 million per well, a reduction of 35%. Modifications and brownfield cost is reduced by 45% and in addition, we have reduced our SG&A by 30%, optimizing our staffs and services and more efficient business follow-up. This is a continuous hunt for further efficiencies while maintaining a high focus on strengthening safety. The persistence demonstrated by organization is truly inspiring. Now let me shift to the outlook for the next years. As you've heard, Eldar has already presented our sharpened strategy for high value and low carbon.
In my presentation, I will elaborate on why we believe our next-generation portfolio is highly competitive and a strong investment proposition. Before doing that, let me show you how we will continue to improve our business, capturing lasting effects. This year, we raised the bar with an additional $1 billion in cost savings, realizing the forward impact of improvements already made and continuously improving all parts of our business, further strengthening our cash generation. We are working hard to lock in these improvements from the efficiency program and capture further market effects. We will continue to drive performance every day, learning from the best and together with our partners and suppliers, implement best practices to increase value and reduce costs. Reducing the drilling cost even further will be important going forward, and Margareth Øvrum will tell you more about this later.
Simplifying and standardizing processes U.S. onshore will be equally important, and you will hear more about that from Torgrim Reitan in his presentation. OpEx SG&A has been significantly reduced, and we see further potential to simplify our processes and become an even leaner and more agile company. Let there be no doubt that we are on a journey of continuous improvement, making that a core part of our DNA. This is cultural change in motion. We have radically reshaped and improved our portfolio, getting more for less. The average break-even is now at $27 per barrel. At $50 per barrel, the internal rate of return is 20%. The portfolio payback is quick. By 2023, again, at only $50. This underlines the resilience of our portfolio at lower prices.
The portfolio contains 3.2 billion high-value barrels with an average production of 360,000 barrels per day from 2020 to 2022. As the CFO, I am pleased to say that we are challenging also the best projects to become even better. The organization delivers. Let me give you two examples to highlight what we have done. Peregrino Phase Two in Brazil now has a break-even below $45, a reduction of more than 30%. It started with spending the necessary time optimizing and simplifying the concept. We have also captured market effects in the contract awards. Now we are realizing the effects of the increased drilling efficiency and strong project execution. We aim for a production startup in 2020.
CapEx is reduced by close to $1.5 billion, and production is increased, extending the life of the field towards 2040. Trestakk is another example, this one from the Norwegian continental shelf. Here, we have reduced the breakeven on this subsea tieback from 58 to below $20 per barrel. These are not unique examples. We clearly see that there is a powerful learning effect when you leverage it across the entire portfolio. The improvements we have made will also have an impact on the projects with startup well into the 2020s, such as the Carcará field, a deal we made in a low-price environment, capturing value from cyclicality. Value remains the priority, and our improvements have increased our production.
The strong growth in 2017 is related to increased efficiency and startup and ramp-up of fields such as Gina Krog, Ivar Aasen, and Hebron, as well as increased activity US onshore and lower turnaround activity. From 2018 to 2020, we have several major startups capturing significant value in the upturn. The list includes Mariner, Stampede, Aasta Hansteen, and Johan Sverdrup. This contributes to our cash generation, which I will now address. Last year, we said that we could continue with our investment program and be cash flow neutral at $60 in 2017 and $50 in 2018, with a debt ratio in the mid-30s. Today, we are cash flow neutral at $50 of the cash dividend with a stable debt ratio. The improvements have made this possible, and the CapEx reduction in the outlook period is substantial.
Around $10 billion without reducing the flexibility in our portfolio. The balance sheet remains strong with a capacity to maneuver. We have a single A rating on a standalone basis with a stable outlook. We continue to be comfortable with a debt ratio in the 30s. With the current assumptions, we will be back within our long-term ambition of 15%-30% towards the end of the outlook period. Now, let me give you just a bit more detail on how we manage our financial framework to capture high-value opportunities. Our commitment to create attractive, sustainable shareholder value is at the core of our strategy. We have positioned ourselves with a great set of opportunities, and we are investing in world-class projects such as Johan Sverdrup. These are projects with strong returns and radically improved breakevens.
We see a double-digit return on average capital employed at $70 by 2020. For the next generation portfolio, the ROACE is well above 20% when the projects are producing. We are growing our cash flow from the existing operations and sanctioned projects, improving cash margin. We will continue to demonstrate financial discipline, managing short-term challenges while continuing to high-grade our portfolio. We will still have a long-term perspective on investment and return. Our dividend policy remains firm, and the board will propose for the AGM to maintain our dividend and continue our scrip option, and share buyback remains a part of our toolbox. Moving on to guidance. We plan for around $11 billion in CapEx for 2017, and exploration spend of around $1.5 billion.
Value is our priority when increasing our production, and you can expect a growth of 4%-5% from 2016 to 2017, and around 3% annual growth from 2016 to 2020. We continue our efficiency improvements, raising the bar to deliver $1 billion in additional savings this year. Let me sum up in three points. First, our track record is strong. We have taken down cost faster and deeper and radically improved our projects. Second, we have maintained financial flexibility with a firm commitment to capital distribution. Finally, we are in a strong position to capitalize on our high-value opportunity set. Thank you for the attention. Now I give the word to Margareth Øvrum.
Thank you, Hans Jakob Hegge, and good afternoon, everyone. Look at this. This is the world's biggest spar. It's the Aasta Hansteen. You know, this is 20 m long and 50 m in diameter. If you look at the person in the white circle, that is Eldar Sætre. Our job is to develop and to deliver the competitive solutions which will shape our company's future. This responsibility includes the development and execution of all Statoil operated projects. It is drilling and well, procurement, as well as research and technology globally. No small task, but you know, I have the best job in the world. Eldar Sætre and Hans Jakob Hegge, they have already presented some excellent figures from projects. I will explain how we have achieved these figures. In 2016 has been the most energizing year in my career.
Not only because my boss is pleased with our figures, but because I've seen what we are capable of. As Eldar said, he has been in this company for 36 years. I'm much younger. I've been here for 35 years. We keep on delivering on all our targets, and I believe it is because of who we are. I've never witnessed a more creative and result-driven force. First of all, we have a world-class project portfolio. We make even the most complex challenges profitable, also with low oil prices. We continue to reduce breakevens and increase the value of our projects significantly. This gives us the opportunity to act counter-cyclical, and we sanction projects. Secondly, we seek the real game changers through innovation and technology. In the following, I would like to support my statements through facts, numbers, and examples.
After all, I am an engineer, so I like more figures than words. Our mantra is every single dollar saved today is a dollar we can use to create value tomorrow. It applies to the quality and project execution just as much to the maturing of future projects. To the left side, you see the cost development in our sanctioned projects. In 2016, we reduced the expected forecast to 90% compared to the sanctioned estimate. Some is captured market effects, but more important, we deliver below cost because of our execution performance. Let me give you a few examples. The Gullfaks Rimfaks field, we delivered more than $125 million below estimate, four months ahead of schedule due to efficient drilling, efficient marine campaign, and the quality and execution.
Currently, we are more than $250 million below the estimate on the Dogger Wind Farm in UK. Due to highly efficient marine campaign and also the use of industry standards, $250 million below. Obviously, I will revert to Johan Sverdrup soon. As you can see, we managed to save cost and reduce our estimates. This means that we can sanction new profitable projects, award contracts in a favorable market, and create value for the company. Last year, we sanctioned four Statoil-operated projects, Peregrino-II in Brazil, Utgard, Byrding, and Trestakk on the Norwegian continental shelf. Below the sanction projects, you see some of the exciting opportunities ahead, both short- and longer-term. The first seven projects are planned for sanctioning within the next two years. Currently, these are the ones we have matured the most and have the lowest breakevens.
I can assure you, we work hard to make all of them as profitable as possible. On this date last year, I promised you a non-sanctioned portfolio with a breakeven below $40 per barrel. I just wanted to remind you of this because we have over-delivered. The graph on the left-hand side shows the exact same selection of project we showed you last year. The dark gray area marks improvements in breakeven since then, and the magenta color shows where we currently are. We have not only reduced the breakeven, we have introduced stricter CO2 intensity targets and increased the value of these projects. The CapEx has been reduced by 43%. The resources, at the same time, have been increased with 12%, and the NPV is increased with 12%, even with a reduced oil price assumption of 20%-30%.
Actually, if we had kept the prices fixed, the NPV would have been increased with between 70% and 80%. I also wanted to commend Lars Christian, Arne Sigve, and Torgrim, what they have achieved on production efficiency and reduced operating costs in particular. This learning also improves our projects. Some of this is a result of competitive pricing, and we are on track with regards to expected market effects. However, the main contribution are improvements which will sustain even if the market changes. We change every element and we challenge how can we simplify the concept? How can we standardize on previous projects? How can we utilize existing infrastructure more wisely? How can we use new contract types or models that increase performance? How can we use technology and so on? I believe in setting the impossible target, targets which require radical changes.
In 2015, very few people believed it was possible to reach a breakeven target of $50 per barrel. One year later, the portfolio was $41 per barrel. Today, the breakeven in the next generation portfolio, as you have heard from Eldar, is 27. This demonstrates we can make the impossible possible, and we will work just as hard in the execution phase to beat these figures. We see this positive development in all types of projects globally. Regardless of how good these project numbers or the portfolio number gets, we will not sanction a single project until we have made it as profitable as possible. Let me be very clear, the prerequisite is a strong safety culture. Improvements that do not support our safety work have no place on our improvement agenda.
I promised facts, so let me go into more detail on two of our giants, Johan Sverdrup and Johan Castberg. Johan Castberg is the largest oil discovery in the Barents Sea. With the selected FPSO concept, we reduced the breakeven from $80 to below $45 per barrel last year. Since then, the scope has been matured further, and the current breakeven price is below $35. Such improved numbers do not just appear on their own. This is a result of a project team willing to challenge conventional way of thinking and collaborate closely with the suppliers. Since the CMU last year, we have optimized the field layout, we have reduced the number of wells, but still we have increased the recoverable resources, and we have further reduced the seabed intervention cost.
We have challenged the supplier industry to find new subsea system solutions, and, you know, they have responded. Together, we have simplified requirements which will result in less weight, lower complexity, less documentation, and lower cost. We have now a standardized package specification which we can implement across the whole portfolio. The estimated cost reduction is approximately NOK 40 million per well. Johan Sverdrup is an extraordinary project in size, in CO2 intensity, as well as in the achievement. The project team's commitment is a testament to our mantra, every single dollar counts, and it really proves we are on a journey from improvement programs to a continuous improvement culture. Sverdrup has always been a very profitable project. Still they keep up the intensity and continue to hunt for ways to reduce cost and increase value.
Sverdrup is a phase development, and we have now completed 40% of phase I. 24 million work hours are completed, and most importantly, without any serious actual incident. In August, we communicated CapEx reduction of NOK 24 billion compared to the PDO estimate. Since then, we have reduced it with an additional NOK 2 billion, and this is a result of the best ever drilling campaign, quality and execution, limited scope changes, and the chase for every single dollar, such as optimizing the use of floor material, giving us NOK 30 million in savings. In phase II, the CapEx is reduced with NOK 30 billion-NOK 45 billion since the PDO of phase one.
By setting tough targets, efficient collaboration across disciplines, and the use of experience from phase one, the project has reduced the number of process trains from two to one, reduced the number of wells from 42 to 28, and copied 40% of equipment from phase one. Copy-paste is good for us. Even with the radical cost improvements, the resource range has been further improved. Now it is ranging from 2 to 3 billion barrels in resources for the full field. We have increased the production capacity for both phases to 660,000 barrels a day. As you can see, the updated breakevens are below $20 for phase I, below $30 per barrel for phase II, and for the full field below $25. I'm not sure anyone can beat these figures.
Reduced drilling costs is also a significant contribution to the improved project break even figures. In some cases, drilling amounts to half of the project price. We continue to deliver groundbreaking improvements within drilling and well. Compared to 2013, we have increased the meters per day by 69%. We have reduced the days per well by 42%, which gives a cost reduction of 35%. As you can see on the external benchmark, it's a Rushmore benchmark on the bottom left, we are significantly lower on cost per meter drilled than our peers. In short, we deliver more wells to a much lower cost. This is a result of a continuous focus on simplified well design.
It is a focus on standardized wells, operational efficiency, and what we call the Perfect Well approach, which means setting targets based on the best section drilled ever and driving towards these targets. It embeds the continuous improvement culture we pursue in terms of both safety as well as performance. It is a methodology we have successfully stolen from Torgrim and the U.S. onshore operations. It is also adopted by our projects where the driver now is common cost targets with our suppliers. Within all areas, not just within drilling and well, we have to work closely with our suppliers to succeed. We do not fill the shopping cart with goods and argue the price when we are at the cashier. We collaborate to bring the price down before we get to the cashier.
Together, we work to simplify, to reduce the interfaces, and find new contracts, models that will promote a win-win situation. One example is the integrated drilling and well contracts on Sverdrup and Mariner and Kattegat, or how we have bundled the marine operations together with the subsea on the Trestakk. I believe we have more to gain, for instance, by introducing lean, optimizing logistics, working with suppliers to reduce the non-productive time. As I stated, we hunt the real game changer that can take our competitive edge to a new level. We seek high, high value, low carbon solutions. One example is our roadmap towards a remotely operated factory, an unmanned field development. It is a specific example of what we can achieve by utilizing digitalization, and it will radically reduce our carbon footprint. Picture the big platform, the standard platform, big, heavy, and complex.
Imagine the benefits of having several smaller standardized building blocks as you can combine, allowing for better field utilization and optimization. I simply call it the mix-and-match solution, and everything is operated from shore. We combine subsea with unmanned topside technology to find the optimal solution for each project. It will improve the robustness of our project portfolio by making even the smaller field developments profitable. An early assessment on one of our projects shows a potential CapEx reduction of $1 billion. We see this as a future development solution for several of our fields. It may seem like science fiction, but you know, we are getting close. Believe me, many thought the Åsgard subsea compressor was unrealistic. It has been running for one and a half years now with 100% uptime.
At the CMU in 2014, we presented the unmanned wellhead platform, or as I like to call it, the subsea on slim legs, as our future long target. It is already under construction, and it will be installed this summer, three years later, on Oseberg Vestflanken. Currently, we are developing the unmanned production platform, and the next step will be the unmanned and remotely operated factory aimed for frontier areas and deeper waters, for instance, like the Barents Sea. World records for size belongs to history. We still think big, but we build small. This fits perfectly into the new strategy. It requires less cash, increase CapEx flexibility, and enable us to act counter cyclical and has a significant lower carbon footprint. Based on our technology track record, I am sure we will succeed.
To summarize, we will continue to mature and develop a competitive and carbon-efficient project portfolio. We will maximize the value creation through continuous and sustainable improvements, and we will use our innovative capabilities and technology to fuel radical changes even beyond what we have achieved so far. I believe in the future of this industry, and I know we have both the competence and the determination to shape competitive solutions for the future. I would like to give the word to my very good colleague, the flexible cash generator, Torgrim Reitan. Thank you.
Thank you very much, Margareth Øvrum. It's a fantastic colleague I have, hasn't I? Good afternoon, everyone, and it's good to see you, and it's good to be here in London to give you an update. Last year we discussed, you know, our plan to transform the U.S. business. It is a portfolio of high-quality assets, and it provides a strong fit with the sharpened strategy. The U.S. portfolio is flexible. It can respond to lower prices, and it will capture value in an upturn. But like many others, we invested significantly in the U.S. in a high price environment. As a consequence of the falling prices, we have made impairments and we have negative earnings currently. With that said, we have a first-class portfolio and organization.
You know, I have confidence that we have the ability to make this business work at low prices. As some of you may remember or will remember, this plan has three pillars. First, we're gonna make money at lower prices. That is measured by net operating income or 90-50 ambition. In 2014, we needed $90 per barrel to have positive earnings. In 2018, we'll make money at $50. Second, we are going to improve our operations by 20%-25%. Lastly, and maybe my favorite, we are going to double the cash margin in a $50 environment. Today I'll give you an update on all of this and show you that our plan is working. Let me first update you on our portfolio. Onshore, we have an attractive portfolio in three core areas.
Last year, we increased our share in Eagle Ford, and we took over operatorship from Repsol. We divested non-core Marcellus acreage. Offshore, we have had significant production growth of high-value barrels. In December, we won two blocks in Mexico's first deepwater bid round. The U.S. and the broader part of the Gulf of Mexico is an important part of Statoil and a significant part of our company, and it is our task to make it work. Hard work is what it takes for us to contribute to the targets that is laid out by Eldar and Hans Jakob. How are we doing? We will bring our earnings breakeven from $90-$50. In 2016, we ended about $66, so we are well underway. You know, $90-$50, that is based on our earnings.
The impairments we took two years ago drove most of the improvements from 2014 to 2015. Since last Capital Markets Day, we have taken both impairments, and we have also made reversals, and the net effect of those is very minor. So let's instead talk about, you know, the real improvements. Unit production cost, that came down by 34% in 2016, and alone this drove $4 on this chart. Our onshore recovery rate is at 41%, over the last year, and offshore production grew by 45%. This was driven by new wells and also improving regularity of 94%. You know, these new offshore barrels, they are of high quality with a strong cash flow. But they come with a high DD&A rate.
As an example, Julia has a DD&A rate of $60 per barrel. That means that it contributes positively to the cash margin, but actually it contributes negatively to the $90-$50. These are lasting improvements. To get to $50, we must improve our recovery rate even further. Stampede needs to come, needs to start up safely and on time, and production from existing fields need to ramp up as planned. We need to continue cost reductions and our efficiency gains, and we need to improve our regularity onshore. With this progress and what we plan to do, we can get to $50. Let me discuss our operational targets. Last year gave me confidence in our ability to transform what we do.
In fact, we have already surpassed two out of our 2018 targets, onshore development cost and operational cost per barrel. We are close on the third one, the administration costs. Let me give you some concrete examples of what we have achieved. In the Eagle Ford, unit of production cost is reduced by 36% since we took over the full operatorship of that asset. Drilling efficiency has improved from 19 days to 15 days now as we applied our Perfect Well approach mentioned by Margareth. Furthermore, we have successfully reorganized, we have reduced costs, and our business has now the ability to scale up to a higher activity level. We have reduced CO2 emissions significantly in our Bakken operations, and we are at the forefront in working to limit methane emissions.
You know, we aim to be the most carbon-efficient oil and gas producer. Nothing less. Based on this, we will set new targets for 2018. In 2016, we benefited from low supplier costs and a high-graded drilling program. Going forward, we assume an increase in supplier costs, and we will also drill several pilot wells and test future development areas. We have allocated a pad where we will work together with Margareth Øvrum and her team to test new technology and new concepts for drilling and completion. You know, within onshore, there's a short time from improvement to cash flow. You have seen our Margareth Øvrum's team's ability to deliver.
I'm really looking forward to the way we are working together there, Margaret. With increasing supply costs and these pilot wells, we need to deliver further improvements to meet new targets. This is ambitious, but we are convinced that we can do it. You know, despite all of these improvements, we are not satisfied. We cannot be fully satisfied. We systematically use benchmarking to uncover new potential. We have access to third-party data for thousands of wells, so we can compare our performance to others in the areas where we operate. In most areas, I would say that we compare well, I would even say very well, and that is within the areas of recovery rates and drilling performance. In other areas, we need to improve.
We are lagging on regularity onshore, and we are still not good enough on operating costs. Over the last years, we have spent five times as much money on CapEx than on production costs, so focusing on recovery and drilling has been the right thing to do. Now, the time is right to focus even more on the day-to-day operations. We can do better, and that is what motivates us to improve each day. Our growth certainly needs to be profitable. We need to grow with quality. Our old target was to double the cash margin from $5 to $10 while we grew production by 50%, more than 50%. Our new target is $12.5 per barrel, and this is exciting, and it comes from better performance onshore.
It comes from higher production and improved regularity offshore, and it also comes from lower costs. You know, while our new fields offshore do not help much on the 90-50 due to the high DD&A rates in their initial phase, these offshore barrels contribute a lot to this one, to the cash margin. We still expect to grow around 50%, or production by 50%. But let me be very clear, I do not have production targets, and my people, they does not have that either. We focus on safely producing value. Nothing less than that. You know, we aim to be a cash generator for Statoil. We have been in an investment phase for many years, and so far we have spent a lot more money than we have made.
In a couple of years, we will have a positive free cash flow at $50 oil. At higher prices, the cash flow will be substantial, as you can see from the left side of this chart. Then, you know, the CapEx flexibility that we have, that is gold for Statoil. Our future investment options are increasingly attractive. We have improved the well economics significantly, and we now have more than 1,000 well targets with a breakeven less than $50. We are optimistic that we can get many more wells into this category. Our plans tell us that we know we're building a sustainable business at lower prices. Let me summarize. We are still negative net operating income. However, the plan we introduced last year, it is working.
We are on track to make money at $50 in 2018. Our operational improvements are progressing, and we are setting new efficiency targets. At $50 oil, we will have a cash margin after tax of $12.5 per barrel. The U.S. portfolio, it is flexible, it can respond to lower prices, and it will capture value in an upturn. We are reducing our carbon footprint as we go forward. All of this is very much in line with the strategic principles that Eldar outlined earlier today. It is still early days for the U.S. business. As of today, we have only produced 11% of our economic resources. Our portfolio has a large potential, and our business is scalable. My team and myself, our job is to make money and to create growth options for Statoil.
We are prepared to add acreage when we see the right opportunities. You know, with our assets, the capabilities and people, the next chapter of the U.S . Journey will be a very exciting one. I'm feeling that I'm already now looking forward to update you when we have progressed this journey even further. Thank you very much. I look forward to your questions and to discuss with you. Then I leave the word back to you, Peter. Thanks.
Thanks, Torgrim. Thanks, everybody. I'm pleased to say that we're right on schedule. A little bit of choreography now while I invite Eldar and Hans Jakob back on the stage to take your questions. We're gonna have roving mics for everybody in the audience and also mics on the tables where we've got the executives as well, so we'll be able to to do those. If you want to come through there and on that one. We aim to take questions for around 50 minutes. I know this is a long session. There's a lot of important messages we think are good ones that we want to get through and give an opportunity to discuss. I know I have something of a reputation for being fairly disciplined in terms of our approach to the questions.
I'm gonna reinforce that discipline. I'd like to keep it to one question, preferably in one part, with the promise that if we get through those and there's some spare, we will go round again. This is something where we want to give everybody an opportunity to ask those questions. We'll do this one 50 minutes max. There'll also be plenty of opportunities afterwards, when we see. The first hand I saw was Brendan.
Thanks, Peter. It's Brendan Warn from BMO Capital Markets. Just coming back from the last set of results and probably just looking forward, just this whole deferral of production for value and for cash flow, can you give us sort of an idea of the amount or can you quantify that value for me? I'm not allowed to ask part B of that.
You can ask a part B if it's related.
Yeah. I guess for Torgrim, I mean, in the past, we've heard about the onshore business, or I'd say the U.S. going to 500,000 barrels a day, a lot of additional promises. Where are the pushbacks going to be or where are the more difficult parts of your portfolio that you're dealing with and in terms of future divestments of your current portfolio?
In terms of deferrals, I assume you are referring to the gas flexibility that we have in our upstream portfolio on the Norwegian Continental Shelf. It is important for us to utilize that flexibility to create value, not to run after production volume targets or anything like that, and we've done that consistently over a long time. I think net, the net position now that we have deferred some volumes, I think it corresponds to around 20-25,000 barrels per day in volume. Not a significant deferral, but this is something that goes up and down depending on how we look upon the market at any point in time. Highly valuable, and we use that flexibility. I guess the next question, Torgrim, was for you.
What I could say on the, you know, I said in my strategic comments that we will continue to operate, improve, and also add acreage. Torgrim is preparing the business to a stage where we feel comfortable earning the right to do that. He's pretty much there now. We are ready to bolt on, add acreage to this, business. It is a highly valuable component of our overall portfolio, the flexibility of it, the cash resilience, and so on. In terms of how we would like to do that, divesting, investing, that is something that, you know, we will look at whatever opportunities is at hand. There were no more specific comments on that. I think to the question, Torgrim, you might add some comments. There is a microphone there, I think.
I think this is working. Thank you, Brendan. First of all, 500,000 barrels per day in production target, those type of targets are long gone. We don't use those type of targets. We are focusing on value, and we see production as a vehicle to create value. We have changed our targets from being a top-line target, you know, production, to be a bottom-line target, earnings and making money. That's sort of, you know, we can just disregard the 500,000 barrels per day. Then on the difficult part of the portfolio, I would say it's very encouraging to see that the underlying profitability of the portfolio is changing.
You know, deepwater Gulf of Mexico has been seen as a very challenging part in the current price environment, and I'm very glad to see that, you know, also those projects are improving significantly. We have over there, you know, improvements, you know, in sort of maybe not as impressive as Margareth talks about, but still, you know, very impressive. I would say, for instance, the Vito development that Shell is developing and we are joining is now looking at break-evens in the low 40s. Onshore, the more difficult part in the onshore portfolio, I would say if you take Bakken, I mean, the Montana part is sort of still there. It needs to be worked.
We haven't focused a lot on it, and that's why we are joining Margareth and, you know, with a pad in that area to see how much we can actually get that on as such. But it will take research, it will take technology, and it will take a bit of stamina long-term to make that work. But I think ultimately we'll get there. I can talk about Eagle Ford and Marcellus as well. Marcellus, I would say Ohio part of the Northern Marcellus and Utica is coming across as very promising, you know, the well rates there. Always, of course, the Northern Marcellus and the gas fantastic, you know, break-evens, but exposed to local prices, as you know.
Those assets are actually free cash flow in the current price environment, so they are working.
Okay. Take the next question from Theepan Jothilingam.
Sorry, Nick here?
Yes.
Thank you for taking the question. It's Theepan Jothilingam from Exane BNP . I just want to talk about the balance between investment levels and the balance sheet. My question is how should we think. Let's say oil prices don't necessarily go up as quickly to the sort of $75 outlook, but in the next couple of years around current prices. How do you see what a sustainable level of investment is, particularly given the good work that you've done improving breakevens against deleveraging the balance sheet and, you know, essentially initiating a buyback program? Thank you.
Investing in new capacity, high quality asset is definitely a priority for us. That is how we create values and also can distribute capital to our shareholders and so on. We have a high quality portfolio, and it is a priority while maintaining the commitment to capital distribution. We can do both. We have indicated through the presentation that you gave, Hans Jakob Hegge, that the current gearing level is sustainable in the mid-30s at an oil price of $50 per barrel. If the oil price should turn out to become $70 or even $75, that we have assumed as our long-term price assumptions, this will significantly improve our debt ratio and our financial capacity.
It is we have the capacity to invest in the current opportunity set, but it will always be value-driven. If we don't have, you know, sufficiently attractive high value opportunities at hand, that will have an impact on how we prioritize in this environment. In terms of priorities and capital distribution, we're very firm on the scrip program. We extend that in line with what we indicated last year. There's no change in that plan. You know, the board has the discretion to make adjustments, but there's no plans to extend it or shorten it. That's basically what you should expect that we will move forward with that.
In terms of buybacks, that is an option that we keep as a mandate. We ask every year the AGM to give us that mandate, and we will keep that. As long as we have a scrip program in place, I don't think you should expect us to introduce any share buybacks. Beyond that, I think you know priority will still be to you know in terms of gearing a debt ratio, we are very comfortable in the thirties, but we would still say that we have an ambition of, and long-term ambition of getting into a range of 15%-30%. That will still be a kind of a priority to get into that range.
Overall, you know, all these priorities is something that will be looked upon at any point in time, given the quality of our opportunity set and the outlooks that we are looking at at any point in time.
Okay. Gonna do Mehdi, and then I'm gonna swing over right at the back to Lydia, and then that will give an opportunity to Tim bring the microphone on this side. Mehdi next.
Hi, this is Mehdi Ennabati from Société Générale. I will ask a question regarding, let's say, the non-sanctioned portfolio breakeven. I would like to compare April with April, because last year you highlighted during the CMU 2016 that the breakeven is $41 per barrel for the non-sanctioned project starting up by 2022. Margareth Øvrum highlighted that now we are, let's say, close to $27 per barrel. But this takes into account Johan Sverdrup. I would like to compare April and April, so excluding Johan Sverdrup. How did you manage to decline this $41 per barrel, just in order for us to measure your efforts?
Just would like to come back to the slide number 23, and this is why in fact I am asking the question. You provide, you know, the breakeven average per project, and we can see a project, which is at $10 per barrel breakeven. I wanted to know if this is Johan Sverdrup phase one. Thank you.
It's a very good point. We have tried to be very prudent. Defined in my presentation exactly what is the 10-27, the next generation portfolio, kind of a brand. What is that? It is not the same portfolio that Margareth talked about last year and referred to here, which was at $41. That was a portfolio including Johan Sverdrup. It was basically a non-sanctioned project at the time of the previous CMU, but still in production by 2022, and Statoil-operated project only. That portfolio, Margareth, you have to correct me, would have a breakeven price of around $30 per barrel.
It's 30. That's right, yeah.
The same portfolio. 41, 30.
It's from 70 to 41 to 30.
What I would like to show you now is what I call the next generation portfolio. The whole portfolio opportunity set with the next generation mindset, which includes Johan Sverdrup. It also includes partner-operated projects, which actually has a higher breakeven than our portfolio. Still we include that. That gives you a feeling for our whole portfolio, which financially, you know, will have an impact for the company. The difference is basically the partner-operated components, which is in there, and Johan Sverdrup mainly, which is in that portfolio. That's the precise difference between those two portfolios.
On the figure you had in your presentation. Is $10 the breakeven for you on Sverdrup? It's not. No, it's not. We won't tell you which project it is, but there are great projects which is at the very low profitability. High profitability and low breakevens. Okay. All right. Lydia, in the distance.
Hello there. Hi. Thanks. It's Lydia Rainforth from Barclays. If I could ask a question about the cost savings numbers, and obviously you've increased that target as of today to save $1 billion and then beyond into 2018. Is that now a stretch target in terms of that cost saving number that you have? Possibly for Margareth Øvrum, you have made those cost savings look relatively easy, and I know they haven't been. What do you think is the biggest challenge going forward for those?
Okay. If you take the first question, stretched or not, and then Margareth, prepare for the next one, all right? Well, I think it's been very encouraging to see that we have over-delivered by NOK 700 million. You're absolutely right, Lydia. It's not been easy. It's been hard work and across the entire organization. It's many contributions to that. That's why we with confidence talk about the culture of continuous improvement. Is it a stretch target? It is a tough target, and it's for this year. We expect to see within facilities related to sanctioning projects, but also further market effects that we have talked about in the past. The market effects in the NOK 1 billion is around 200-ish of the total billion.
Just for the record, I mean, we talked last year about $300-$400 million in market effects. It actually turned out to be a bit higher. Or more, around $450 million for last year. Including in the 3.3, and then the additional one is around $200 million. Margareth Øvrum?
What are the most challenging? First of all, I would say we have to deliver on it. It's dependent on our execution capabilities, which I've also proved today that has been very good. But of course, if the prices is getting up again, we have already said that 10%-20% of the savings are related to market and market capitalization. If the price is getting up again, we just have to fight that. But I would like to say once again that we have tried really to reduce the cost side by sustainable reduction by simplification and standardization. What we can do if the prices is going up again is, first of all, we can ensure we have sufficient competition. There is various forms of competition.
You can have different suppliers, or you can have different concepts. For instance, the unmanned platform toward a subsea solution. This is one way we can act. At the same time, I think it's also very important that we collaborate with our suppliers. If you collaborate very early, we can find the best solution. Maybe it was a long answer, but yeah.
Thanks, Margareth Øvrum. We're gonna do three questions from this side of the table, and then we're going to take some questions that we've had on the phone. Kicking off with Marc Kofler.
Great. Hi, everyone. It's Marc Kofler from Jefferies. I just wanted to ask a question which I guess is reasonably similar to the previous question, but on the capital spending and the guidance for this year, particularly in the context of the evolution in the guidance and capital spending that we saw in 2016. How much wiggle room flexibility is there in the 2017 program? And should we, you know, should we expect, is it even possible to get the same kind of gradual decrease in capital spending coming through this year that we saw last year?
Following on from that, I just wanted to clarify if how significant the NOK currency assumption in the capital spending program for this year is. I think I saw 8.5 on one of the slides. Thank you.
I think I'll leave it to Hans Jakob to address this.
Yeah. Thank you for asking that question, Marc. As you're aware, we started off with a level of doubling. We're coming from a level of $20 billion down to last year's $10.1 billion. The efficiency gains has been tremendous. What's the further potential? What's the sustainable level? We guide over around $11 billion for 2017, and we say it will be somewhat higher going forward in the guiding period. We have maintained the flexibility of $4-$6 billion that we talked about last year. We don't have to sanction the projects according to the plan if
We plan to do so because we think we have a strong value proposition, very attractive returns at this level and a break even of $27. In terms of the exchange rate, you are correct. Yes.
Thanks, Hans Jakob Hegge. Could I just say, you know, in relation to the break even cash flow that we talked about last year, that was what we could do.
When we talk about $50 this year, that is what we will do. All our projects is included in that roadmap for 2017 and going forward.
Okay. Martijn Rats.
Thank you. It's Martijn Rats here from Morgan Stanley. Eldar, just a question for you on the DPI business, the international upstream business. If you take a step back, sort of broader than just the US, you've sort of said in the past that you've not been so happy with performance there and there's room for improvement. I just wondered if you can give us an update on where you see that business going in 2017. It sounds like some of the headwinds around DD&A mean that maybe, you know, results from that business will still sort of have a bit of a transition phase in 2017. Is that a fair assessment, or do you think that we'll start to see some of that improvement already this year? Thank you.
I think I will offer an opportunity for Lars Christian to comment on his part of the business. We have addressed the US business. In general, from my perspective, the international business in the balance sheet looks slightly different from the Norwegian Continental Shelf. It is a younger portfolio, obviously then also a higher cost portfolio. It has been acquired in slightly different ways as well, at least part of the portfolio, which actually make us reflect market values in the balance sheet and not historical, you know, development cost. That gives us depreciation, DD&A per barrel, which is, I think in this quarter, 2.5x what you see on the Norwegian Continental Shelf. Nothing I could do about that. It's history. This is where we are.
My focus is on value, and value to me is about cash and how, and improvements. My, a good starting point to develop this portfolio. It will be part of our strategy going forward. SG&A OpEx is down around 30% in the international portfolio, which is on par with what we are seeing in the rest of our business. Really, I think there has been a really good progress. Torgrim has addressed his progress. Lars Christian, if you would like an opportunity to comment on your achievements.
Yeah. Thank you, Eldar. In addition to SG&A down 30%, our operating expenses is down 30% since 2013. CapEx spending down 50%. In 2013, we expected a manning increase in range 20%-22% towards 2016. It's actually down 20% compared to 2013. So this is across the whole board. If I look at my portfolio of assets, I have some of the best assets in the company internationally, and then I have some not so good assets, which is the case across the whole board actually for the company. Last year, I said that the net operating income before exploration would be positive at $46 a barrel. I delivered that result at $45 a barrel.
The realized oil price for last year was just south of $45 a barrel. It's so easy to sort of just focus on the oil price last quarter, which was kind of higher, definitely. The first quarter for 2016 and the realized oil price for the international part of the business was, you know, well below $30 actually. That is what I kind of have in the baggage for the whole year of 2016. As Eldar is saying, the DD&A is 2.5 times the Norwegian Continental Shelf for fourth quarter 2016. For the full year, it's twice as high. The cash flow after tax per barrel basis is at par with NCS. It is a strong portfolio, but it has its challenges and has had.
We have worked extensively to improve it, and we are not fully where we would like to be. You see also us doing some portfolio adjustments. We have exited one, you know, asset, and we have acquired a couple that will definitely also improve the composition for the international part of the portfolio. One comment on, you know, regarding the new projects going forward for the international part of the business, we see the exact same improvements as we do for the NCS projects. Breakeven is down by $40 so far, and we're still working many of these projects to bring them forward in due time. Thank you.
Thanks, Lars Christian. One more from the floor, then we're going to take some from the phones, and then I've got a cluster of questions in the middle here. Hamish.
Thanks, Peter. It's Hamish Clegg from Bank of America Merrill Lynch. I think we can all agree you've done an excellent job on the cost-cutting program. The efficiencies have gone extremely well and appear to have brilliant momentum going forwards as well. As we feel we're exiting a trough in the cycle for the sector with oil prices starting to look slightly better and a good outlook, the focus for some of us shifts on to the discipline side. We see the momentum in your cost-cutting program. We'd like to maybe if you could allude a bit more to the options in your portfolio for your resource base. You gave us a 20 billion 2P resource number today, which is great, nearly 30 years.
Could you expand a little bit on a couple of things for me? First is how much of that is coming from Lundin and Johan Sverdrup? Second, beyond that, with that exploration program, where will the focus be? Can we see more opportunities in Brazil? And you didn't mention the prospectivity in the northern Barents as well.
Thank you.
Okay. I'm glad to have Tim Dodson here, who is heading up our exploration business. I addressed exploration briefly in my presentation. That was at an aggregate level. I will give Tim the opportunity to answer that question. On the resources reserves, the nature of that, Hans Jakob, could you add some color to that?
Yeah. I thank you for the question. I had the slide on the organic RRR over 90% in a year with limited contribution from exploration. We had very strong operating momentum, adding volumes from the existing fields. On Lundin is 1.65.
Could I also just say before you get the word Tim that, you know, referring to Lars Christian. A lot of the resources is outside of Norway. We have some assets that are pointed towards the beyond 2022 portfolio. Which is in many ways predominantly portfolio outside of Norway. There are also Norwegian assets, but most of the big Norwegian assets will be done that we know today. We depend on exploration. The big assets are outside of Norway. We are improving that portfolio, as Lars Christian mentioned, quite significantly. We are not prepared to give sort of details. You will find them in the graph on the page that Hans Jakob Hegge illustrated.
They are improving, but we really, really haven't addressed them as forcefully as we have been doing on projects like Sverdrup and Castberg and others. We expect significant continued improvements on that portfolio, and that is really, you know, also what is part of the resource base.
Okay. Yeah. Thank you very much. When it comes to exploration, our focus going forward will be more or less the same it has been for the last few years. Our results have not been as good as they were in the period 2011 through 2013 when we proved up close to 5 billion barrels of the current resource base, the 20 billion. We have been focusing the last two years in reloading, basically replenishing our portfolio. That should come as no surprise, as we drilled out what turned out to be a very good portfolio in 2011, 2012 and 2013. That's really what exploration is about.
You know, sort of I always say that for every prospect you drill and test, it moves out of my portfolio, whether it's a dry well or a commercial discovery, which I hand on to my development production colleagues. It is about replenishment. Our focus going forward will be, as it has been before, a balanced and attractive mix of exploration activity in prolific basins. We have a very attractive program in Norway. In fact, in sort of if I include U.K. into that this year. We have good follow-up opportunities in both Canada and Brazil, again, prolific basins. Then we have select higher risk frontier opportunities that can represent breakthrough opportunities in terms of big discoveries with the potential for standalone developments.
That will be our focus going forward. Good opportunity set this year, as I say. I think the perspectives for next year are also fairly good given the fact that we've loaded up with so much and such good quality acreage over the last two years.
Okay. Thanks, Tim. We're gonna take four or five questions from the phones now, please. Thank you. Then we're coming back into the center, and I'll kick off with Oscar.
We will now take our first question from Anders Holt from Danske Bank. Your line is open. Please go ahead.
Good afternoon, guys. Actually my questions have been answered already, so I'm good.
We will now take our next question from Pia Dorn Nielsen from Swedbank. Your line is open. Please go ahead.
Good afternoon, and thanks for taking my question. One question on CapEx. You said that the normalized CapEx level going forward will be $12 billion-$14 billion. I just then wonder what kind of supplier prices does that range assume? Do you assume any increase from today's level? Then just a follow-up on the exploration question. Could Tim mention some specific prospects in the Barents that you like? Thank you.
In terms of the supplier cost, basically what we have assumed into the numbers are contracts that, yeah, I mentioned $30 billion of contracts that has been awarded and options that are added, you know, added to these contracts. These, you know, the way we have structured them gives us optionalities in terms of using the same contracts into new projects. We have, I would say, a pretty good overview of prices and the cost of supplies in the conventional portfolio that is included, so we haven't taken any bets on something beyond that.
When it comes to the onshore in the U.S. Permian, we see already, I mean, in the conventional part, we see still a lot of capacity in some of the segments in the rigs, for instance. There is a lot of rigs, spare rigs that hasn't got a lot to do in marine activities, ships, a lot of capacity in many segments, which will, you know, in many ways impact the, for quite some time, the cost of supply. When it comes to the U.S . Situation, it's more dynamic, more responsive, and I think Torgrim already sees that there are, you know, some pressures on cost of supply. That is already included in his assumptions and also, in fact, included in the improvements that Torgrim was showing in his presentation.
Tim, expected that one on the Barents Sea. Please, share your comments.
Yeah. Okay, thank you. Thank you for the question. As Eldar already mentioned in his presentation, we'll be testing a number of high impact opportunities this year. Just did a quick count. I think it's six which I've communicated, where all three of those in the Barents Sea, Korpfjellet, Koigen Sentral, and Gemini North. The three others, in case you're wondering, is Verbier in the U..K, and it's a prospect in Suriname and a prospect in Indonesia. I would hasten to add that the first four are moderate risk. The second, the last two are typical high-risk, high-reward frontier prospects.
Thanks, Tim. No, no. Couple more questions on the phone.
All right.
We will now take our next question from Anna Gjøn from DNB Bank. Your line is open. Please go ahead.
Yes, good afternoon. Thank you for taking my question. I have a question related to tax. In fourth quarter, the tax in Norway, I see this is surprisingly high, and my understanding of this is that it has to do with reduced uplift. With such low investment level going forward that stays low, what kind of impact will that have on your tax? I understand that for the company as such, it is difficult to give tax guidance, but is it possible to say something about the tax rate in Norway, but with, for example, oil price of $50, $60, $70? Thank you.
So.
He's the tax expert now. I used to be.
Yes. Thank you, Anna, for asking that question. In the quarter, we had a tax rate in Norway of 72%. That's in line with our guidance. You're absolutely right. When the results go up and the CapEx goes down, the tax rate will increase. We haven't changed our guidance. Next question on the phone.
We will now take our next question from Halvor Nygård from SEB. Please go ahead.
Thank you. Two short questions. Firstly, in your production guidance, it looks like if you plan to produce around 520,000 barrels a day in DPN flex gas in the U.S. onshore in 2020. Could you say something about the split between the two? That is, how much is flex gas and how much is U.S. onshore? And then secondly, you mentioned that you're looking to add one to two new core areas, both offshore and onshore. Can you give some more color in terms of geography, type of hydrocarbons, timeline, and if it will be organic or inorganic? Thank you.
One to two. Yeah. Expected that question. I think it's too early to tell. We are looking at, you know, we've heard today about a very interesting exploration portfolio. That could take us to certain places, not all the places that Tim is exploring. But you know, we know hopefully we will get some exploration success that adds materiality to the portfolio, and it could be related to places where we already have legacy assets, or it could be totally new places. In the offshore, it is obviously there are some good opportunities. We see East Coast Canada and Canada as one of them. We didn't mention drilling on in Canada, but you will drill wells also East Coast Canada, this year. Gulf of Mexico. Mexico.
Wider Gulf of Mexico, including Mexico, is definitely one option. You have access acreage in frontier acreage in Gulf of Mexico, two licenses. Again, which, you know, not being drilled this year, but which is ahead of us. In terms of Mexico or Gulf of Mexico, we are in the process of reviewing, taking another look at sort of how to understand geology and prospectivity in that region. These are examples of what could be, but there could also be other opportunities to build those kind of core position. That doesn't mean that the core as it or countries will be the only places where we are, but that we see the potential to develop scale, you know, scalable and material positions in one to two additional offshore countries. Onshore, it's again too early.
We are exploring many opportunities, both from an exploration perspective and from a business development perspective, John. Russia is one of the countries where we are pursuing several opportunities, both offshore and onshore. That could be one of the onshore opportunities, but it's too early to conclude. Let's say one to two, and it's just a guiding to telling us that we are doing more than just hanging on to Brazil and the U.S. onshore. We are really looking to build a more robust portfolio of core countries also outside of Norway.
Yeah. That's it?
That's it.
Mm-hmm.
One more from the phones, and then we'll go through to a cluster of questions through here.
We will now take our next question from John Olaisen from ABG. Your line is open. Please go ahead.
Hey, good afternoon, gentlemen. A question to the slides from Hans Jakob Hegge. Hans Jakob Hegge, you say that the projects that start up from 2015 to 2022 will have a return on capital employed, average return on capital employed of above 10% with an oil price of $70 in 2020. First, it sounds a little bit low. But I was wondering if you could comment a little bit on that. For instance, what kind of gas price assumptions do you have behind that? And maybe just as importantly, do you think this portfolio of projects will pull up or pull down the average return on capital employed for Statoil in 2020?
Yeah.
So.
Yeah.
The last one is up. Oh, I think I got feedback. Okay. The last question, it goes up. About the returns, I think we're coming from a lower level of returns that's been quite moderate, the last year, it's fair to say. Going forward, a return above 10% and an internal rate of return well into the twenties, I think that's a clear direction and a very valuable and attractive value proposition.
In terms of gas price, we are now d isclosing. Disclosing the price assumptions. Basically, you know, in 2020 we are talking about a $6 per million BTU European gas price and a $4 Henry Hub price.
Yeah. No, six.
We're gonna come back onto the floor now, and then we've got a cluster here. I'm gonna kick off with. Well, actually, I'm gonna go first with Oswald Clint. Nearly there. You'll all get your questions.
Thank you. Yeah, I really wanted to follow up on one of those previous questions, Eldar Sætre, about new growth options in the international upstream business. And obviously looking out to a rising oil price scenario, $75-$80, it obviously forgives a few sins in terms of M&A. You've spoken about a lot of impairments through history. Maybe talk about business development and what criteria you specifically look at today going forward. What's changed there to ensure that you're really acquiring or accessing high return projects, you know, regardless of the oil price, please. Then secondly, if I can just follow up on one of Margareth Øvrum's charts talking about the recoverable resource stepping up 12% or so over the last three years.
Is that the normal level of resource creep that you've seen over your experience? Is that higher than normal? If so, what's really doing that? What, you know, is that something we should expect to continue on that new portfolio? Thank you.
First on business development, Tim, now John, you might want to add to my comments here, but I stated in the strategy that, you know, this very conscious strategic direction of being counter-cyclical is important. We have been that, and we will definitely try to be even more counter-cyclical. That doesn't mean that we you know, we could sell and buy, you know, at any point in time, given that the portfolio and the assets are, and the buyer and the seller is the correct one. But you know, generally we would like to do this in an efficient way, a counter-cyclical way. I think the mindset that we do that, Tim do on exploration, John does on business development, exactly the same as Margareth has on her assets.
You know, it's not about the long-term assumption. It's really about building resilience, cash flow at all times, and the principles that we established. We need to see project, even if we have to put a price on the table to access project that really has the potential to fit into the kind of resilience, of, in terms of breakevens that we see and we like to see to sustain and be robust against whatever kind of uncertainties that we might have. I don't know if the oil price is going to be $75, just an assumption. We want to build resilience into that portfolio. On top of that, John is working on optimizing and looking at, you know, projects and that we can, you know, support cost efficiency, synergies.
For instance, on the Norwegian Continental Shelf, unlock even small stuff that we did last year on Utgard and so on. It is really a value-driven M&A strategy. It has been highly successful so far, but it is even more important that, you know, in the future that we hang on to the strategic principles that we have established. I don't know, John, if you want to add to this.
Sure. Business development is a mixture of buying and selling. You saw that we took advantage of the selling side for 2012-2014 at about $12 billion. If you go back over to 2010, it was about $25 billion of proceeds and about $12 billion of profit. Not that simple. On the acquisition side, if you look at what we've done this year, we've basically been doubling down in places that we know. Some of those acquisitions around Lundin, that's about $540 million up on a mark-to-market basis at the moment. Not that simple.
With regard to Carcará, taking advantage of the downturn, we've had a lot of interest from many companies, including big name IOCs in farming into that acreage. We're looking forward to building on that when the n ext, licensing round is announced in Norte de Carcará. What was done in Carcará is the beginning of a very significant opportunity, and there's still opportunity for value creation in what Tim and I do in that area.
Okay. Thanks, John. I'm gonna go for Biraj, and then Anish, and then Rob. Biraj is next.
Hi. Thanks for taking my question. It's for Torgrim. Just following up on one of the other questions on service costs. Could you just clarify what you're seeing right now in terms of any kind of service cost inflation? What's baked into the plan, and, you know, do you see that as a risk to getting from 90-50 breakeven?
Okay, Torgrim, do you take that?
Thank you very much. We feel that, you know, we have reached sort of the bottom of the cost curve within onshore. We're seeing increasing activities, at least in the next, you know, particularly out of the Permian Basin. We also noticed that our suppliers are starting to want to discuss, you know, supply cost again. We have assumed a 20% increase in supply costs over the next couple of years into the numbers, and that is to me are pretty robust assumptions. That is consistent to. We should be able to deliver on the $90-$50 with quite a significant growth in supplier costs. The main driver for $90-$50 is efficiency, not market effects.
That efficiency is sustainable deliveries and that will, you know, we continue to deliver on through this period.
Okay, thanks. Anish.
Thanks. It's Anish Kapadia from Tudor, Pickering, Holt. I had a question on your reserves. Statoil compares fairly poorly versus peers on reserve life, and I think it's a pushback from some investors in terms of looking at Statoil relative to peers. When I look at your resource base, it seems like you've got about 3 billion barrels of resource that has been sanctioned and a further 3 billion barrels of resource that works at sub $50 that hasn't been sanctioned as yet. I really wanted to get a sense of how does your reserve replacement, how do you expect that to trend over the next five years or so as you bring some of those projects online and you also sanction some further projects?
Obviously the resource base contains both the resource that is booked today and also resources that, you know, we expect to be booked, you know, as we drill wells and creates more certainty according to the criteria that is established for that certainty going forward. Some of the project is still not at the break-even levels that we would like to see, in particular, you know, in the international portfolio, significant improvements, but still room for further significant improvements. We are confident that these projects will translate into resources, but it will take time to develop these resources and into reserves. I think we have a track record now of showing what we are capable of doing.
All I have to do is put Margareth there, Margareth on the task, and she will deliver the kind of returns that we see both from our current assets, and we will also make sure that we pursue the same strict criteria in terms of the assets that we acquire, that we explore for, that these are assets that has the potential to feed into the future resource base. In terms of expectations, I said briefly that we expect our reserve replacement ratio to be on average above 100% over the next few years. I can't guarantee on a specific year. Looking at what we have at hand and how we are working to mature these assets, drilling more wells, I'm sure we will get more reserve also on Julia, Torgrim.
That's the nature of it and that's what we expect to see over the next few years.
Thanks.
Rob.
Thanks. This is Rob West here from Redburn. One of the messages I'm taking away from today is that you could have taken CapEx much lower if you wanted to. You haven't given us the number of where you could have taken it, except when I get my ruler out later and read off your slide. If you wanted to say a number, that would be welcome. You're spending more than that because of countercyclicality and desire to grow. On page 23, you give us a useful 20% IRR at $50 oil on these upcoming projects, which are the basis of the growth.
My first question for you is, you know, to me at 20% IRR, it makes sense to put that money into new projects rather than getting rid of the scrip or paying more of the dividend or a buyback. But is there a hurdle that you need projects to clear where you maybe are not so sure and say, "Actually, 10% or some lower number, yeah, I'd rather give it back in cash"? That's the first bit. Secondly, related to that, I'm sorry to break the Hutton rule about two questions.
Oh, no.
It's one for Margareth, I think. That 20% IRR pre-sanction, I'm guessing that would not be too dissimilar to IRRs on projects that you saw pre-sanction, previous points in previous cycles. I guess one reason those IRRs might not have been achieved previously is because of reinflation once projects get going and change orders and design weaknesses. Could you talk a bit about higher levels of design certainty going into these projects today? I guess you talked about simplifying them, so they should be less complex and less prone to overrun. Is there more engineering per project going in on that list of projects you showed us a little bit later in the presentation? If you could say anything about that would be great.
Okay. I'm very reluctant to give any hard lines anywhere really. That locks in sort of flexibility and, you know, in terms of what is good enough for a project. I think we are impressed with what we had achieved and what Margareth has achieved, $27 breakeven. You see there is a range of projects and a lot of them hasn't been worked yet. To say this is the kind of project that we won't invest in and we will do something else with the money, that, you know, I can't offer that kind of hard line and criteria.
Like what I can say is that, you know, the oil price assumption, gas price assumption is not kind of a criteria that it used to be. You know, we look at NPVs and so on based on our long-term price assumptions, but really what is the key criteria now is, okay, is this project as good as it can be? We are value driven, so we have time to wait to make it as good as it can be. You know, or do we have the resilience and the best outcome and then, you know, that is a more important criteria in terms of breakevens than actually in terms of does it meet the criteria in relation to an oil price assumption. A very different mindset.
I would say the oil price assumption is more actually for an accounting purpose than for decision-making purpose in terms of the new projects. In terms of project and certainty on this, and I would say Margareth, you know, was very clear again that we take the time. We did, you mentioned the Peregrino II project. We spent one more year. We felt it was not good enough. One more year, and we significantly improved the returns in that project. We had actually FID the project. Then we stopped it. Hey, we can do better. We spent the time that it takes to improve this project, and that means a lot of, you know, processes, more quality up front loading in a way, but also in terms of challenging the projects.
This is not setting a team to design something. It's really, is this the best design? That kind of process is really also very important for us, that we have teams that circle around and address challenges to projects. The Snorre future project, for instance, that is a project that was a new platform. We start to challenge that, and suddenly it's a subsea. We didn't think it could be. By doing that process, you know, taking the time, we turn around and come up with totally different solutions. You need to do that. Once we have the project, I don't think we do more engineering or any more, you know, work into the scoping, but we spend more time to make sure that we have the right fit for purpose solution.
Now, Margareth, you have at least an opportunity.
Yeah. Yeah. Yeah.
To add to this.
Yeah. First of all, I think we do it in another way. We start with the minimum solution. We start with design to cost. If we need to add something, it must be value creation. I feel we are maturing the projects in a better way. I think we start earlier with involving all the suppliers to really get the best solution. It's not only with Castberg. We have postponed a bit because we thought we could do it better. We have had proactive teams to really challenge us, and it's the same with Trestakk.
I think we work differently because we have people challenging and we start by the minimum solution and not the very big solution as we used to do. We are not using more engineering hours, but we are maturing the projects better prior to sanction, I would say.
All right. Thank you. I'm gonna take the last question now because we're running a little over time. Tom?
Thanks, Peter. It's Tom Robinson from Deutsche Bank. Just one question, and it really relates to strategy in the new energy business, which I think, Eldar Sætre, you effectively started your comments off today on. Would you just talk about the very long-term shape of cash flow in that business and how you measure success in that business? And the way I'm thinking about this is, to me, it feels like, you know, you go through an investment phase that potentially may last a number of years. If you follow the CapEx outlook that you presented in slide 11, certainly a number of years. When do you move out of that investment phase into something that generates cash for the group?
The earnings from Irene was positive in the last quarter. We don't report it, but it was positive, so we are already there. I think, this is a very different business. It has a different risk profile. Maybe slightly similar when it comes to project execution as such, but when it comes to the revenue side and the operation side, it's very different. Also, the risk profile gradually will change as we will take on more market risk. That will make it also more similar, but not quite, because it's different markets than we see within upstream oil and gas. To me, this is attractive, but you have to relate it, the attractiveness and the reward to the risk profile of the relevant projects that you're talking about. That's something we always have done.
We relate projects to project-specific risks. Pipeline project, for instance, different risks. They're more regulated than EMP projects. We have seen, you know, returns in the range of 9%-11%. 11% is basically the Belgian project. The Hywind is more at the 9%, the pilot project. That's kind of returns that we see, and these are quite a distance from the cost of capital to these projects. They are creating value on behalf of our shareholders. Forward, you know, we will look at the same type of returns, but they will always, if we see higher risk, more market exposure, we will look for returns that is, you know, capturing that and rewarding us for that. It also offers opportunity in the marketplace.
Instead of having a fixed revenue, you can really work the market. The condition for all of this is that, Irene here is able actually to deliver project. I don't allocate 15%-20% of anything. I give a roadmap here on the slide in terms of how this could look like. I think it will be backloaded. I think Irene will have to struggle, fight really hard to get project to fill into something like that. If she doesn't, we won't. If she does, we will. It's really a tough commercial exercise exactly in the same way as we do within oil and gas.
Thank you. With that, I'm going to call the Q&A session to a close. Is there any summaries at the end, Eldar, that you'd like to say?
I hope you got a good understanding of where we are. I really tried to come through today explaining that we have fundamentally reset this company. In terms of cost, how we run it, in terms of efficiency, but also the opportunity set. That, in many ways, comes together into when I can say that, you know, we can actually be cash flow neutral at $50. Not only today, we can do that going forward. That's the place I didn't think we, you know, where that we would be actually. Now we are there. That gives us a whole set of new opportunities, high-value opportunities. I think also we have, for the longer term, strong organizations, strong capabilities to add resources to our business through business development.
We have demonstrated it through exploration. Be patient. We have demonstrated it in the past, and I have full confidence in our capacity to not only run the short term and our current portfolio, but also sustain our oil and gas business while also developing a highly profitable renewables business in Irene. Thank you very much for coming. Really appreciate it. Look forward to see you all again next year.
Thank you very much.