Hello and welcome, ladies and gentlemen, to OMV Strategy and 2015 Results Presentation. My name is Felix Rüsch. I'm the head of investor relations of OMV. Before I give you a quick overview of today's agenda, let me introduce to you today's speakers. We have with us today the CEO of OMV, Mr. Rainer Seele, the CFO of OMV, Mr. David Davies, the executive board member responsible for upstream, Mr. Johann Pleininger, and the executive board member responsible for downstream, Mr. Leitner. Thank you very much for being with us today, gentlemen. Let's have a quick look at the agenda of today. Mr. Seele will kick off with his presentation for about 45 minutes, followed by Mr. Davies. We will have the first Q&A session of the day, followed by a lunch break.
We will come back at around 1:30, listen to the presentations of Mr. Pleininger and Mr. Leitner. Mr. Seele will come back for a quick wrap-up. Thereafter, we'll have a second Q&A session. At this stage, I'd like to hand over to the CEO of OMV. Mr. Seele, the floor is yours.
Good morning, ladies and gentlemen. On behalf of the entire OMV board, I welcome you to our strategic event today. I would like to give a short presentation about the financial performance we have shown last year in 2015. I, of course, will give you a brief overview about our OMV strategy. My colleagues and their presentation will go into more details so that we can discuss it also with you in more detail afterwards. I will close my presentation with an outlook for 2016 and of course, also strategic outlook for a target year 2020 in our strategy. Before I'm going to run into the financial KPIs, I would like to talk about the top priority in our company, and that's our license to operate to show a very good safety record. As you see in this chart here, we are well on track.
We are well on track to reduce our LTI rates from 2012 to 2015. We could steadily work on our safety performance, and I think we are on good track and the way forward is, of course, we would like count to zero, which is the target within our companies. Within three years, you can see we more than halved our LTI rate. We will continue to do so. Let's talk about our financial performance in 2015. Well, on the first look, you might say, well, the financial performance is not as good as I have seen the HSSE performance of OMV. That's the first look. If you look at the numbers over here, you see a little bit the structure. In the EBIT structure, what was the market development in 2015?
In terms of EBIT, yes, it went down by EUR 800 million because of the lower EBIT contribution from the Upstream business in OMV. This is just reflecting that the oil price has halved last year compared to 2014. We are dealing with a $52 per barrel. Of course, the contribution of Upstream was less, whereas Downstream was contributing on a higher level as we have seen record refining margins. The EBIT performance of Oil Downstream especially was doubled in 2015 compared to 2014. This chart is also explaining that the integrated business model and business structure of OMV is some kind of a natural hedge, especially in times when we're going to see a low oil price.
The Downstream contribution is even more reflected if you have a look on an earnings per share level, because Borealis also have shown a record year in 2015. On a CCS earnings per share level, and if you look at the just pure operative business last year, 2015, we even could outperform 2014 by 1%, although we have seen half the oil price than in 2014. On a free cash flow level in 2015, we could show up on a free cash flow before dividends, more or less break even. As we are targeting a free cash flow break even after dividends, we in the board have decided that we recommend a dividend for 2015 of EUR 1 per share, also reflecting that we have a different business environment in 2016.
The dividend is more or less reflecting the change also of our outlook. As we speak about the oil price assumption, what you can see in two steps, we have adjusted our oil price assumptions. As we speak about 2016, we started with a $75 per barrel when we were in the mid-phase of our operating plans. Then we made already an adjustment of $55 at the end of last year. Our actual outlook for 2016 is now $40 per barrel. Also in mid to long term, we have adjusted our oil price outlook from $105 per barrel to $75 per barrel. We are a little bit more conservative as we speak about the oil price outlook, and that was the reason why significant impairments were triggered with the revised market outlook.
You have seen that we have some impairments of EUR 3 billion from impacting the numbers in 2015. 80% roughly are allocated to the Upstream business, reflecting just the oil price outlook we have changed. Roughly 20% were allocated to the Downstream business. If you look into the numbers, you will find out that this is, in the first instance, our power plant in Turkey, Samsun, and it is our Gate terminal, the LNG terminal in Rotterdam, where we couldn't use the capacities. Let's come to our strategy of OMV now. If I would headline our strategy, I would use three words: profitability, focus, and sustainability. Profitability comes with lower costs, lower CapEx, lower exploration.
Focus comes with a portfolio optimization that OMV will go for oil and gas and not for electrons, that OMV will focus on specific regions, that we are going to be a regional player, not a global player. Sustainability comes with a full reserve replenishment. A clear target that we would like to replenish our production, our reserve base by 100%, and we target an R/P ratio of eight to 10 years in our strategy. Before I'm going to run into the strategic numbers, I would like to talk a little bit about the markets and about the business environment of OMV and how we do see it in a framework of, let's say, the next five years. The oil markets right now, it's a clear picture. It's an imbalance of supply and demand. We do have too much oil in the market.
It's so much oil that we don't know even how to physically store all the oil. That's the reason why we are not very optimistic in short term on the oil price. I don't see that drastically short term, the picture will change. I think the market has to deal with the oversupply situation in the market. Of course, there's a little bit of incentive because of the low oil prices that people like to drive more their car and the cars are getting bigger, and that especially in the OECD countries, a little bit of demand is coming up, but this is really not covering at all the situation on the supply side. I think the oil price will be driven in the trading markets more from the supply than from the demand side.
Everybody's asking, what's going on when Iran will come on stream with additional volumes? Who is going to make the room for additional volumes from Iran? OPEC is changing their strategy. Who knows what kind of role OPEC is going to have in the future? I ask myself, is OPEC the swing producer like we have seen in the past? Right now, it's a big question mark. The same picture is in the gas market. Just one more sentence on the long-term outlook on the oil price, why we think that the oil price will recover. If you look how the industry is reacting right now on the oil price, we have a low oil price now the second year in a row. The industry reacted because of the low cash flow. We are going to cut investment spending.
The CapEx cuts, while you can read numbers of EUR 500 billion-EUR 600 billion, I don't care what number it is. I only know that many projects are on hold or even are not being followed in that oil price environment. That's the reason why I think with the time lag effect, we will see an impact on the supply side, supporting our outlook that the oil price will recover mid to long term. In the gas market, same picture. European gas market, I will focus my comments on the European gas market. Same picture. We are going to have an oversupply gas market. The winter is not helping at all. I haven't seen a real winter.
That's by far too warm, so we have lots of gas, and that's the reason also why the hub price is reacting to a level of EUR 13 per megawatt hour. Well, we have seen in summer last year 20, something around 20. Yeah. This winter is not as good as the summer last year. Price-wise. Therefore, we do have lots of gas in the market. The big hope of additional gas demand from power generation has cooled down. Of course, also OMV was thinking five years ago or so that we will have a very strong gas demand, especially coming from power generation. Well, looking into all the Energiewende and that we would like to go for green electrons, I am not very optimistic as we speak about additional gas demand. In the mid to long-term outlook, I think there is an opportunity for gas.
The opportunity is gas replacing coal. That's going to be our marketing strategy in OMV. We will target the power generation segment, and we will target especially that we are addressing the huge advantage of gas compared to coal. A last short remark on the refining market. In refining, we have seen record margins last year. Has the market changed? Not at all. Has something changed in our refinery? Well, of course, we do have a cost-cutting program and efficiency programs in place. Not at all. We still have overcapacities in the refining markets in Europe, and they have not disappeared. In our long-term outlook, there is a strong need, as we have said also in previous years, that we have to reduce capacities in the European market. The market is pretty well supplied.
That's the reason why we don't think that the fundamentals have changed and that the record margins in refining will continue in the next years. Let's have a look to the operative performance of the three business segments of OMV, in Upstream, Downstream Gas, and Downstream Oil. Well, what I have shown here is the operating performance covering the last five years. In Upstream, you see that from a level of EUR 2 billion of EBIT contribution, we are now down to something around EUR 140 million. The development is reflecting just the oil price, but it's also reflecting that our production, we have lost our production in Libya and Yemen. Roughly something around 30,000-40,000 barrels per day, so which is 10% of OMV production.
By the reduction of the oil price and the EBIT, also our operating costs went up, and that's an issue I will address to you later on. The same picture we have seen in the EBIT development of our Downstream Gas business. As you can see, from a level of around EUR 200 million EBIT performance, we are slightly negative in 2015. What is the reason behind that? First of all, we had a very painful excursion into the power market. It did not pay out for us. The spark spread disappeared. Nobody in the industry really can talk about a good story investing in the gas-fired power plants. Also OMV not, but we have done it on a lower level than our competitors.
The excursion into the power market and into the power business was not helpful at all and is negatively impacting our overall results in the Downstream Gas business. Secondly, the market has changed from a border price market to a hub price market in Europe with a very high transparency. As a consequence of this market change, the transparency was absolutely there and our margins came under pressure. The all-time margins or the old margin level we have seen in the gas trading markets, nobody believes that they are coming back. We also not. That's the reason why I think that the margins will stay under pressure, but we have to find a solution for one big cost component in our gas Downstream business, that's a high level of booked infrastructure capacities. I will come back to that.
In Downstream Oil, just a contrary picture. Steadily growing EBIT performance as we have done our homework in Downstream Oil pretty much. We have reduced our refining capacity by 20%. We have improved our efficiency in the three refineries. We have, of course, reduced our cost position. We are one of the leading companies as we compared our refineries in the Solomon Studies in terms of cost. We are highly cost competitive. What I want to say is, also in times where we haven't seen record-level margins, Downstream Oil performed very nicely, although on a different level. Especially in 2015, I repeat myself, we have seen the value of our integrated oil and gas business. We have seen that we do have a natural hedge between upstream and downstream. Our strategy is pretty clear. We will continue to be an integrated company.
I keep that hedge for the future, especially as I think that we are going to see a period of time of a low oil price coming up, we are not cross-substituting our business. We will follow a strategy that each business unit has to be profitable on a standalone business. That's the reason why we have, in each business unit, a headline for the strategic target. In upstream, we follow a strategy of value over volume growth. We will focus, we will cut costs, we will focus on different regions. We will set a priority on profitability instead of setting a specific volume growth target. I don't say that we don't see volume. There is an upside potential in the upstream business. As we speak about the priority, money comes first. Not money spending, profit getting from the upstream business.
We have some homework in the upstream sector. In Downstream Oil, we will keep the strategy in place. No major changes. We are going to look on the cost positions. We will further reduce our cost basis. We will increase our efficiency. We will keep Downstream Oil as a strong cash generator in our portfolio. No major changes. Only one, I will come back to that. Downstream Gas, we have to take notice, as I have said, that the market has changed. As the market has changed, we have to adapt our business model. That's the reason why we have to restructure our natural gas business into the new environment. What are our strategic upstream priorities in OMV? In upstream, we will follow a strategy which is short-term, a cost optimization program, nothing else.
Independently what oil price we are talking about, it's unacceptable for us that we do have production costs, which are roughly 10%-15% above the average of our competitors. If we would like to stay competitive, OMV has to bring costs down. That's our target. At least we would like to be break even, to be in the average line of our competitors. Therefore, our main priority is we have to bring costs down. Short-term, my colleague, Hans, will talk about that in more detail. Long-term, there is a strong need for us to move into regions where we're going to have a low-cost production, more or less fine-tuning our portfolio. Costs and profitability will also come with a strong focus. We will not discover our planet in every region anymore.
We will focus on three core regions, I will come to that, and on selected development areas. Sustainability will come with a reserve replenishment rate of 100%. Let's have a look on our reserve replenishment. We couldn't manage in the past. Not a single year we can show up on a net basis that our exploration strategy is good enough to perform 100% reserve replenishment. We have to question whether or not OMV should continue with a strategy that we purely put our card on exploration, especially in times where we have a stretched cash flow in our company in a low oil price environment. Long-term, OMV will continue to build on specific strategic partnerships. What kind of partnerships do I have in mind? Especially the partnerships in our core regions and in our development region.
I'm talking about a company like Statoil, who is a very good partner of OMV in the North Sea. I'm talking about ADNOC and our shareholder, IPIC, who's a very good partner in the Middle East, in Abu Dhabi. I'm talking about the NOC. When they are back in Libya, we have an experience of decades of good working together. We are talking about Gazprom, which might open up as a very big opportunity to work also in upstream in Russia. We know the partner since 48 years. We will build on these partnerships. What you see on this chart is our regional focus. We will have three core regions in our upstream portfolio in OMV. How do we define a core region? A core region is defined that we would like to have a sustainable production of at least 50,000 barrels per day.
That's the break-even level we would like to implement. Not on the first day, but as a step up, we would like to see that because we think it's a critical mass which is a good basis that the regions can finance themselves on a standalone basis. On a standalone basis means that the investment program on a long term should be financed on the operational regional cash flow in the regions. The regions are over there. Hans will go in more detail later. It's here in Europe, Romania, and Austria. It's the North Sea, and it's the Middle East and North Africa. We have only two development areas, so a very strong focus. The development areas are especially the UAE and Iran, as new opportunities are showing up there, and Russia. Why have we chosen these development areas? For a very good reason.
Just comparing costs and reserves. We can't ignore that the vast majority of oil and gas are located in these two regions. In Russia, around one-third of the world gas reserves are in the country. In the Middle East, the vast majority of oil is in the region. Therefore, we should go into the regions. On the first look, you can see here a comparison to Northern Europe, that there is plenty of reserves in the regions. The second argument I have is a cost comparison. The cost comparison shows you that we do have very attractive acquisition costs, especially in the two regions in the Middle East and in Russia. Well, the M&A market in the Middle East is totally different than the M&A market in Russia. Those are not very easy to get access, but OMV will manage.
In the Middle East, we do have a very strong shareholder, and in Russia, we can manage with a very good partner. We will partner ourselves to be successful in Russia. What is very important, if you look to the lifting cost, while this is finding development production cost, you have to put on depreciation, then you have lifting costs, it's not directly comparable. As an indication, one-fifth of the lifting cost we see right now in average in Northern Europe. What it also tells me is, especially in times where today we are going to see a $30-$40 per barrel, well, we can really make profits in the two regions if we would have these regions as an asset in our portfolio. We will do our best, especially in terms of the low costs in these upstream regions. Let's talk about volumes.
As I have said, we are not targeting a specific production growth. What we see is we do have a very good chance to increase our production from a level of 300,000 barrels per day to at least 360,000 barrels per day in 2020. Given the fact that we are going to reduce our capital spending with a reduced CapEx budget, we can maintain in the existing portfolio at least the production level we do have right now. The 300,000 barrels per day, with all the investment projects behind we do have in a low oil price environment, we keep that level of production. There is an upside. There is an upside of Libya and Yemen. If these two regions are coming back, there is an upside of 10%, but the upside here is already existing in 2015. Don't take me wrong.
That's not an upside which is coming on top. It is an upside we do have already over here. Comparable, we would have 330,000 or 340,000 barrels per day production if Libya and Yemen wouldn't be shut in. The real upside is coming with Russia. Russia in 2020 is coming with a 10% upside. You say it's about 30,000 barrels per day, and you might wonder yourself why it's only 30,000 barrels per day. It's because we are in the ramp-up phase of production in 2020. The real impact of Russia of the Achimov 4, 5 will come beyond 2020 on a much higher level. I will come back to that in the next chart. What is important to be mentioned here is how attractive this upside position is for OMV.
If you see that we can improve our upside, our production by 10%+, we only need 5%-10% of our upstream CapEx spending to manage the upside in Russia. What I'm saying is 90%-95% of the upstream CapEx we need to maintain the production level, and 5%-10% of our CapEx spending we will use to get our upstream position in Russia on board. The picture over here shows you how attractive this opportunity is for OMV. What you see here is the production profile of Achimov 4/5. On the first look, we see that we are not talking about a pure gas project. It's a gas condensate project, so roughly 30% of the production are liquids and 70% are gas. The reserve base is 2.4 billion BOE on 100% basis, so our share is roughly 600 million BOE.
A very nice and stable production profile. It will ramp up here. That's why I have said it's only 10% in 2020, and you can see that this is going up in the years after. What is important, we have a 24.98% share. We will have a start of production in 2018, so it will kick in our numbers as everything is running according to plan. A kick in of first production in 2018 already. In two years we will see already a first impact. We do have a specific roadmap behind our asset swap with Gazprom. Right now, we are just in the middle of the due diligence. We do have to prove that this production profile, the source is the Russian Mining Authority. This is not the outcome of our due diligence.
We have to check the field, we have to calculate really very precisely to get an idea about the value of the field. We expect that the signing of the contract of the asset swap will be in 2016. What I'm saying is during the year 2016, we definitely do know whether or not the 10% upside in production will come or not. The probability is there. I will not give you a guess how high the probability is. Closing of the transaction we expect is going to be next year. What I'm saying is in 2017, we're going to close the deal, and in 2018, we will already have a first impact following the production profile in our numbers. Given the huge reserve base of 600 million BOE, we can change our reserve replenishment strategy. We will not purely go for exploration.
We will go with such a transaction, which is an indirect acquisition of reserves. We pay with projects and not with EUR. We will have the room now that we can reduce our E&A spending over the next years. What I'm saying is the reserve position of 600 million BOE is so big that we do have 100% reserve replenishment for the next five years. I don't have to hunt for the barrels. I don't have to hunt for a fight against a production decline. I have the room left now to stabilize my cash flow by reducing our spending on exploration, and we are just right in the trend of this process. As you can see here, we have reduced exploration from 2014-2015 already by nearly EUR 100 million, by 12%.
In 2016, we will go down to a level of EUR 450 million, so another 26% reduction. Our strategic target starting 2017 is EUR 300 million in exploration. Well, I would say this is really a very big chunk of positive impact on our cash flow. The same picture and strategy as we look to our CapEx spending. We will have a very strict CapEx discipline. We are on the way forward to further reduce our CapEx spending. We have reduced from one year to another. From 2014, we have cut EUR 1 billion. We will further cut 13% to a level of EUR 2.4 billion. That's below the CapEx range we have told you in our roadshow half a year ago, which was EUR 2.5 billion-EUR 3 billion. We will go beyond our CapEx level, and we will build on flexibility. Why do we have that kind of reduction?
It's because we do have a certain basis of committed CapEx spending in our projects. Year by year by year, the CapEx commitment will go down and will give us room in 2017, 2018 onwards to decide whether or not we're going below that numbers or above that numbers. It's strongly depending on our cash development and therefore also depending on the oil price development. Come on. All right. What is even more important is a comparison. What did OMV compare to its peers? We have reduced our CapEx spending by 37%, which is even more than our peers have done in the past. All right? We will have another cost-cutting program in place, and this is the manageable cost. We have told you that we want to reduce EUR 150 million.
We have cut in 2015, we have cut EUR 200 million, and we will go for another EUR 100 million cuts in costs until 2017. Let me talk about the gas downstream strategic priorities. Very easy. We have three challenges. One challenge, I already explained to you. We have booked a big chunk of infrastructure capacities, and we have not managed to have a market outlet. We are not making our capacities we have booked busy. That's the reason why we do have a big cost basis. I have found an easy answer. Just go for the market. Just work hard to get the market position so that we can make the book capacities busy, and then we don't have to swallow the cost purely without a business behind that.
That's the reason why we have announced yesterday that we start a market offensive in Germany, and we are targeting a 10% market share there. The second challenge is I don't like regulation, honestly, because I'm an entrepreneur. That's the reason why OMV will invest into non-regulated business. We will invest into non-regulated business because the regulator determines the tariff. He determines what kind of investments we have to do. He determines the rate of return. He determines even the people working in the company. What do I have to say? If I would like to be in the driver's seat, come on. The regulator is driving the regulated pipeline business in all over Europe. That's the reason why we have decided to sell 49% of Gas Connect Austria, and then we are going to invest into Nord Stream 2.
While minimizing the power activities, I have told you already. What is Nord Stream 2 about? You can see that we are going to build two additional pipelines directly from Russia towards the German coast. It's another capacity of 55 BCM. It's a strong European consortium. E.ON from Germany, Shell from Holland, OMV Austria, Engie from France, and BASF from Germany, each have 10%. We do have an equal shareholding, 50/50 in this project between Gazprom and the European partners. The total investment, roughly EUR 10 billion, including investment costs. Our share is 10%. It's EUR 1 billion. Taking a 70/30 debt equity financing, we are talking about roughly EUR 300 million equity share of OMV. That's until 2019. It's a real minor project or a small project in the portfolio of OMV. What is the strategic rationale behind? Two reasons. Stability. It's a state-bond character.
We have agreed on a firm rate of return on our investment, which is very attractive for us. It doesn't matter whether the sun is shining, we have a high or low oil price, we have good or bad gas prices. I even don't care whether they ship gas or vodka through the pipeline. We get our rate of return because we are selling the capacities and we are not selling the ship volumes. I don't even care if somebody is going to buy the gas in the European market because we are participating as an investor based on the agreed rate of return. It makes highly economic sense for us to participate in such an investment project. On the other hand, there is a strategic component because the majority of the gas will flow to Austria and will feed the higher liquidity to Baumgarten.
It's making Gas Connect Austria more busy and more valuable. It's making the gas hub in Austria even more important. Downstream Oil, we will maintain the strategy with strict capital and cost discipline. We will strengthen our business, especially the integrated margins. We have done a pretty good job because we prolonged our contract with Borealis until 2028. We have designed the business with a captive outlet for our refineries. That's the principle of integration. We do have Borealis for the C2, C3 stream. We do have our retail stations for our middle distillate. That's the concept, and that's the reason why I think we do have a captive outlet and a very good business. There is only one big issue we have to manage as a challenge, and that's Petrol Ofisi. Petrol Ofisi, we are going to sell up to 100%.
Well, take away the up to. I would like to sell 100% because it's a strategically and isolated asset in our portfolio. There is no integration. What I have said, no backward integration to any refinery of OMV. Our strategy to work on Turkey couldn't be implemented successfully. We couldn't manage to come up with the Nabucco. We couldn't manage that we have our own equity upstream gas and oil production in the neighborhood of Turkey. We couldn't get a sustainable power business with our Samsun plant, and we went for just lots of apartments in Turkey. Because the regulator, the regulatory impact was so high that we have been capped with the margins in the retail business. We see some upside. Now we have prolonged all the contracts with our retailers.
I think it's the right moment to sell the business and to free up cash for OMV. Same story with Gas Connect Austria. I don't want to repeat myself why we are going to sell Gas Connect Austria. All I'm going to say is, it's going to be a competitive international process. Gas Connect Austria is very attractive, especially for potential financial investors who are satisfied with investments with a rate of return of 4%-5% after tax. That's not meeting the minimum hurdle rate of OMV. That's the reason why we would like to lift capital with the 49% share we would like to sell. We keep 51 because I think we want to keep our financial control, and we would like to keep it on our balance sheet. The outlook for 2016, I make it short because I'm running out of time.
It's going to be a challenging year for our entire industry. We expect that we will have a lower price of around EUR 40 per barrel. Of course, we might not see the record level of refining margins in 2016. Our integrated business model, and I'm convinced, will also work in 2016. We will get a natural hedge profit contribution from the downstream sector to cover the pain we do have right now in the upstream sector. We will have a gas market under margin pressure. It will continue in 2016, not a high level of contribution, but I think we will do our best, especially that we have taken over EconGas. With 100% share, we can drive the business on our own, and we will do that. We will see a production level, well, pretty much on last year's level of around 300,000 barrels per day in 2016.
Our answer on the low EUR 40 per barrel is a cost-cutting program that we go down with CapEx spending, that we go down with exploration appraisal, and that we will go down further with our managerial costs in OMV. What is the strategic outlook for 2020? What is our strategy in a nutshell? We will focus on cash and costs. We will focus on cash and costs means profitability has priority. We are targeting a free cash flow after dividends at latest in 2017. We will go for sustainability, which means it's in upstream, which means we will have in the next years 100% reserve replenishment, and we are not volume-driven anymore. We are targeting profitability and cost reduction in upstream. We have to restructure Downstream Gas. We will not invest. We will even more divest gas via power plants.
We will divest our shares in Gas Connect Austria to lift cash. We will invest into non-regulated business in Nord Stream. We will Europeanize our gas sales business to get a higher sales position to cover the cost for infrastructure capacities we have booked. We will continue to strengthen our business in Downstream Oil. The only story is we have to exit Turkey. In one sentence, OMV will go for cash and profits. Thank you. David, you can talk about cash and profits now. You are the collector. Go ahead.
Thank you, Rainer. Good morning also from my side, ladies and gentlemen. What I want to do now is move on, as Rainer said, to briefly a summary of the Q4 results. I won't spend as much time as normally because what I'd like to do more is talk about some of the financial priorities embedded within the strategy which Rainer's just discussed. Coming to the results, the fourth quarter clean CCS EBITDA at EUR 187 million was down substantially on the same quarter last year, clearly at EUR 545 million. The biggest reason, as you can see here, is the decline in Upstream profitability, driven exclusively by and large by the lower oil price. Production was slightly down, but the 43% drop in the oil price to USD 44 as an average has clearly been the primary reason for the decline of profitability.
Compensated slightly by Downstream overall, but within Downstream, of course, we had a very strong performance from the Downstream Oil business. Refining margin is very strong. Petrochemical margins, although slightly down on Q4 last year, were still strong for the year as a whole. Unfortunately, it was offset largely by a deteriorated performance in the Downstream Gas business, which as Rainer has touched upon, remains a challenge in Europe. Oil sales volumes were lower than the same quarter last year, predominantly due to Yemen and Libya being fully out of production this year, whereas they did contribute slightly to our sales the year before. The gearing ratio improved to 28%, which is clearly within our 30% parameter guideline. That follows, of course, the issue of the hybrid bond of EUR 1.5 billion, which we closed in Q4 last year.
This gearing ratio down to 28% is despite having made special charges of EUR 1.8 billion during the quarter predominantly due to our changed oil price set assumptions, but I'll come on to say more about that in a moment. As you'll also have seen from this morning's announcement, we did decide to reduce the dividend from EUR 1.25 to EUR 1. It's a difficult decision for us to take. We had tried very much to maintain it where it was. If you remember the conference call a year ago, I said that if we had USD 50 at the end of this year, it would be a challenge to maintain the dividend that we had then. I'd rather think that had we had USD 50 today, perhaps we wouldn't have had to make this decision. Clearly we don't have USD 50 today. We have USD 33.
An expectation that the oil price would improve during the year, but nevertheless, USD 33 puts us in a very challenging position. We felt it was prudent on that basis to reduce the dividend down to EUR 1 a share. The Q4 results here. Again, you can see that reported EBIT at the top there, clearly very substantially negative, minus EUR 1.7 billion following the special charges that we booked. Financial results was positive. Here you see, in particular, the contribution from Borealis, which was much stronger than last year. Taxes, very challenging in an environment, clearly, where you're booking losses. What you have here is a EUR 403 million tax income. Tax at the moment in this environment is based on assumptions rather than cutting checks to revenue authorities. The assumption is, of course, the charges that you're booking, when will you be able to offset them against your taxes?
Over what period of time? In what jurisdiction, and such like. It really is quite a challenge. The reported tax rate was 24%. Clean tax is almost anybody's guess, quite frankly, but very low. Certainly in single figures at this point in time, given the losses that are based on the charges that we've booked. Not all of those losses have been recognized as offsetable deferred tax asset positions because, of course, you have to be rather prudent in terms of the period of time you expect to be able to recover them. Tax is based at the moment on our calculated assumptions. Minority interests were more beneficial to us this year. This, of course, is the minority stakes in Petrom.
Also, to some degree, given the Gate provision that we booked in EconGas, the fact that 35% of the stock in EconGas is owned by other shareholders. The losses there offset created this positive position in terms of the minorities. That brings us on a reported basis to net income for our shareholders of just over a billion loss, which is equivalent to EUR 3 a share. If you clean it for the special charges that we made, our clean EBIT in the quarter on a CCS basis was EUR 187 million, down 66% on the same period last year, and the clean CCS EPS at EUR 0.55 is down by 48%. Special items, I've talked about. Clearly the predominant change following Q3.
Q3, we also booked provisions having adjusted the oil price set, with further deterioration in the oil price, forced us to reconsider what we're planning on now for Brent, as you will have seen in the trading statement, is for $40 as an average this year, $55 thereafter, and slowly rising until 2020, when we're assuming $75. That puts us more or less in the middle of the pack. We have no better information or knowledge than anybody else. What we seek to do really is place ourselves in the middle or to the lower end of expectations to try and be as prudent as we can be in this difficult environment. The consequence of which was that we booked something like EUR 1.5 billion in terms of unscheduled depreciation in Q4.
Over and above that, we decided also to take a further provision against the LNG obligation, the LNG shipping obligation, and associated transport capacity bookings around the Rotterdam terminal of Gate, which caused us to book provisions, which is the large part of this EUR 261 million. In total, it takes us from a clean CCS EBIT of EUR 187 million to a reported EBIT loss of just over EUR 1.7 billion. Cash flow. I can perhaps point out here something which we actually find quite encouraging. If you look at the sources of funds here, EUR 3.2 billion in 2015 is more or less exactly the same as it was last year. This is despite the oil price collapsing during that period. Clearly the Downstream business was very strong in terms of cash generation. We feel that this is really quite a robust and solid performance.
Down at the bottom, free cash flow before the dividend payments, broadly neutral, minus EUR 39 million. A lot of effort went into improving our cash position during the year. You can see what's caused us to go from the same here to a worsening position is working capital becoming negative. Why is that? Clearly, the collapse in the oil price means that a lot of the supplier credit that we get goes down in value, and we clearly take full advantage of using our suppliers to finance our working capital. At $100, you get a lot more credit for that than you do at $52, which was the average for last year. We went from positive in 2014 to negative in 2015. Reduced the capital expenditure very substantially from EUR 3.7 billion down to EUR 2.8 billion. That helped.
The disposal proceeds last year, we had a big chunk still in here from Bayernoil. Clearly that wasn't repeated in the year just ended. Net net before dividend from EUR 300 million positive down to broadly neutral minus EUR 39. Clearly after paying the dividend, and the dividend here cash-wise was the same in both years, EUR 1.25. We went from EUR -377 to EUR -569. So much for Q4. Clearly, we're available for any more detailed questions after this. What I'd like to do now is go on and talk a little bit more about the financial priorities during this strategic planning period and some of the challenges and objectives that we're setting. Clearly, cash is king. Cash is absolutely critical for us and everybody else in the industry at this moment.
Achieving a broadly neutral free cash flow after dividend, not just before dividend, but after the dividend, as Rainer has said, is a critical target that we've set for 2016. For 2017, sorry. If you look at 2016 compared to the year that we've just had, the year that we've just had averaged $52 Brent. Our assumption for this year is $40. Clearly, right now, we're substantially below that, but $40 itself is below $52. Of course, we had a very strong year from the Downstream Oil business last year, and we expect a good year this year as well, but clearly last year was exceptionally strong. That puts pressure on the cash flow this year.
Clearly, we're striving to remain as robust as we can during 2016, but 2017 is the year that we hope and plan to achieve a free cash flow position of neutrality after the dividend, although that does assume, of course, the $55 oil price as an average for 2017. The dividend, I've already mentioned. 2015's dividend paid this year rather will be EUR 1 a share, or that will at least be the proposal that we put to the supervisory board and to the general assembly later this year. The dividend policy, the long-standing dividend policy of paying out 30% of our attributable net income remains intact. Clearly, that would hopefully mean that as earnings improve, we'll be able to increase the dividend in line with that. Rating. Clearly, we're a rated entity.
We have Eurobonds in issue, which the rating has enabled us to do, and we have a strong investment-grade credit rating, A3 from Moody's and single A+ from Fitch. Moody's have publicly stated that the whole sector is under review right now. I think there is something in excess of 100 oil and gas companies worldwide, which are currently being reassessed, and clearly, we await the outcome of that. But a strong balance sheet, maintaining gearing ratio below 30% and fundamentally retaining the financial robustness of the company is an absolutely key priority during this period, and particularly in this very difficult environment. One of the things that helps us to do that, Rainer touched upon it repeatedly, is the fact that we are an integrated business. I think that is clearly illustrated by the chart that you see here.
The EUR 3.2 billion on the top left here, you will recognize from the slide I showed you earlier on in cash flow. That is the cash that we generate before working capital, before capital expenditure. That is what the business actually generates. You can see how it has remained broadly stable over the last five years, in fact, increasing slightly versus 2011 by 6%, despite the oil price during that period declining by 53%. Clearly within that, you see the increased contribution, particularly last year from the Downstream business and the declining contribution, logically, given the oil price decline from the Upstream business. But the integrated nature of the business has enabled us to produce that position despite the oil price, relatively speaking, collapsing during that period. Net Operating Profit After Tax has clearly declined because clearly what you are seeing here, particularly in E&P, is a much higher level of depreciation.
This is clean, so the special charges are not reflected here. But clearly, we have been investing heavily, particularly in E&P. That is generating depreciation clearly. That is reflected here in the declining level of profitability, particularly here, of course, where the profitability has almost disappeared with the collapsed oil price. But you have seen here that the Downstream business in terms of Net Operating Profit After Tax, a proxy for cash flow, is coming through very strongly. So we are -22% in terms of NOPAT, but in terms of sources of funds, broadly flat, despite a radically different environment over that period of time. You may remember a year ago also, particularly as the first shock of this first wave of oil price volatility was hitting us, just what kind of break-even prices do we have in terms of cash flow generation, EBIT generation.
I said that essentially all of our production generates cash at a EUR 50 oil price. This is further reinforced here because the EUR 50 oil prices today become somewhat less relevant. The question is, "Well, hang on, you have 33, so how much is generating cash at this level?" You can see here that a EUR 30 per barrel oil price, 90% of our current production generates positive cash. Clearly, the darker blue, or the lighter blue chunk here in the middle is what is between 31 and 50. When I said substantially all, I basically mean everything but this tiny little segment here in the middle. So at EUR 30 per barrel, something like 90% of our production is cash generative, which is clearly very important. What oil price do we need to be free cash flow neutral? 2011 to 2014, on average, we were looking something like EUR 100.
Clearly, we don't have anything like $100 right now. 2015, as I've said earlier, we averaged $52, and the price that we would have needed to have been able to fund the dividend without increasing our debt level would have been approximately $70, which is a 30% reduction on where we've been averaging only a year earlier. Substantial efforts went into that. Clearly, CapEx reduction, cost reduction, huge focus on cash generation has enabled us to get our cash flow breakeven down to $70. Clearly $70 is good, but $33 is where we are today. Where do we hope to be by 2017? What we've indicated here is forget the dividend because you're clearly going to ask, "Well, what dividend will you be assuming in 2017?" Let's assume we don't get into that debate.
If we were to basically say, if we went back to $125, what would we need? We would need about $55 per barrel in 2017, which, by the way, is the assumption that we're making for 2017. If we were not to pay a dividend, we need $40 per barrel. $40 per barrel before dividend is the price of oil that we believe would be necessary to enable us to achieve Free cash flow before dividend. Clearly, what we have to do is, because no guarantees at $40, certainly even less guarantees at $55, make sure that we've got headroom for protection. That's why we've announced the Petrol Ofisi divestment. CapEx flexibility is always something we're going to be looking at. As already mentioned, the Fit for 50 program was a success.
I'll come on and talk about that in a second, we overachieved the target that we've set. Fit for 50 doesn't do you much good when you're in a $33 environment. Clearly that is a process that needs to continue. Cost reductions and efficiency improvement will also remain an essential part of our future. CapEx guidance. Last year we were talking EUR 2.5 billion to EUR 3 billion. We landed in that range, approximately EUR 2.8 billion. This year what we're saying is, 2016, in fact, going forward over the next two or three years, it's going to be more like EUR 2.4 billion. You can see what that actually meant. Clearly the bumper year in 2013 at just over EUR 5 billion included the acquisition cost of the assets that we purchased from Statoil at that point. 2014, EUR 3.8 billion.
The year just ended EUR 2.8 billion and the target for the next three years, EUR 2.4 billion. We've done substantial work ahead of the sector, as Rainer also indicated a moment ago, to reduce our capital expenditure. What we're also doing is reducing our exploration and appraisal expenditure, which was approximately EUR 700 million, going back 2014 and the period before. What we aim to do is in this period, get it down to something like EUR 300 million, to also protect the cash flow. I mentioned cost reductions. We had set a target last year from this Fit for 50 initiative of saving something like EUR 150 million. Initiatives established during the year over a full year to save us EUR 150, and we actually think that what we've been able to do is achieve something like EUR 200 million during the year.
That's obviously been a help to our profitability and to our cash flow. Upstream production costs are down by $3.40 per barrel, to $13.20 per BOE, reduction of 20%. Downstream direct costs have also been reduced by 4%, corporate costs by 12%. Clearly, the discretionary expenditure which you can cut immediately, we clearly did. Headcount also, down by 5% over the same period. That will continue as a process as you look to bring your costs into line with this more challenging environment. Overall, as a backdrop to that, clearly what's absolutely essential is, in terms of financial robustness, is the balance sheet, to enable you to move through this bit difficult environment, without being strained at that level. That's something we've been working very hard to do. Our long-term gearing ratio target has been 30% for some while.
You can see here, we've been broadly around that level and currently stand at the end of Q4 at 28%. You can see also the range of our peers shown with the gray line. That's something clearly which you absolutely need during this difficult period. Being up here, during a price situation that we currently have is not a situation that we want to be in. Clearly, maintaining this strong position is very important to us. As I mentioned already, Moody's have published not only the oil and gas companies, but also mining companies, for obvious reasons, are currently under review. We fully understand that. We await the outcome of that, but these are the current ratings, as I mentioned earlier. We have a very strong liquidity position, not only in terms of unutilized facilities, but following the issue of the hybrid bond in quarter four.
We have in excess of EUR 1.4 billion of cash at this point in time, substantial untapped credit lines and an average debt maturity of around about five years. In terms of access to capital, clearly the group is in a very strong position. Hopefully that's, as I say, by 2017, if we're free cash flow neutral after the dividend, that in any case is not going to be something we'll be looking to access. Sensitivities are critical. Clearly the $40 per barrel on the oil side is very important. You've been aware of this number for some while. Operating cash flow is always difficult to calculate clearly because we have this tax complication with the losses that we have to offset. You can see cash flow is now much closer to operating profit, something like EUR 35 million.
The refining margins similarly, the cash flow here in terms of 80 for every $1 per barrel on the refining margins versus $100 on the EBIT, that might be coming closer and closer together because although we're not making the losses in downstream, in many of our markets, well, there are two markets in particular, Romania and Austria, the losses that we're booking there, we're able to offset against the downstream operations as well. That brings that closer together. Clearly we're also very exposed to the dollar. That's also a source of volatility at the moment. $0.10 change in the euro-dollar relationship is also equivalent to about EUR 180 million in EBIT and EUR 160 million in operating cash flow. Again, reduced in a nutshell, what's the focus in terms of financial priorities? Cash flow. Cash is absolutely king.
Protecting the robustness of the balance sheet during this extremely challenging period is clearly a key priority. As the oil price improves, as we assume it will and plan on that basis and clearly expect it to, then that will give us the capacity to grow the dividend. Once again, coming back to this message, the balance sheet needs to stay in good shape. Thank you very much for your attention and at that point, we're available for Q&A. I would ask at this point, I mean, clearly you can ask any questions, but as Hannes and Manfred will be coming on later on to talk about their specific businesses, Upstream and Downstream, if you have any specific questions on that, perhaps you might prefer to leave that till a little later.
If you can't spend the whole day here, then clearly you can ask any question that you like. Thanks very much.
Thank you very much, Mr. Seele. Thank you, David. We have two assistants here in the room with microphones, so if you have questions, please show me with a sign of hand, and then wait for the mic so that also the people in the internet watching the webcast can understand you. Mehdi, please, you want to start?
Hi. Mehdi El Anbari, Société Générale. Thank you very much for the presentation. Two questions, please. The first one regarding the dividend caps. I will split this question in two questions. First, on your dividend policy, why do you use the IFRS net income to base your dividend policy 30% IFRS net income and not use the clean, let's say, net income, which more reflects your operations and don't take into account the impairments, meaning non-cash charges? Because using the IFRS net income makes this almost impossible to predict your dividend when in that kind of environment. Second question on the dividend. You will save EUR 80 million with the EUR 0.25 that you cut.
I don't really understand why are you doing this given that you will probably sell 49% stake of Gas Connect Austria, which will bring you several hundred million EUR, and you just issued some hybrid bonds for EUR 1.5 billion. As you said, your gearing looks relatively low and your credit rating quite safe. It looks like the remuneration of the shareholders doesn't appear like the priority, and I would like to hear what you say about this. Another question regarding Russia. Clearly, this is the future of OMV growth. You said that the production will start by 2018. We are always in 2016. Can you tell us if the development of this project already started, meaning that it is quite well advanced?
Second, are you, let's say, relatively comfortable regarding any European Commission comments on that deal, given that it is relatively probable that you will provide them your Downstream Gas business or part of your Downstream Gas business?
Dividend. Okay. Yes, Mehdi, on the dividend. Clearly, the target of 30% net income payout has been a target that the group has had since before my arrival, and I've been there long enough. The idea back in 2000 that we would have impairments of this dimension and a shock in the oil price of this dimension was clearly not something that anybody would have conceived. It was really felt that net income was net income. The clean differences wouldn't be very substantial. In terms of the guidance now, clearly the clean number is the best one to look at. That's something we would regard as a sustainable level. The 36% payout ratio that you calculate based on the dividend we've just declared is certainly based on the clean CCS net income.
That's the guidance that if anything, we'd like to push you to because who knows where we will be going forward. If the oil price starts to recover, then clearly the prospect is there that we have to write back these assets that we've written off. That kind of movement in the balance sheet is something we try and see through. The guidance really should be around the clean number. The question why we do it. Yes, we clearly have a roster of two significant assets which we're trying to dispose of. The GCA asset, which we would hope to close this year and more likely next year, the Petrol Ofisi asset. The fact of the matter is we haven't closed them.
The fact of the matter also is that although we're assuming EUR 40 this year and EUR 55 next, as we sit here today, we have EUR 33. Although the interest of the shareholders, the interest of bondholders, the interest of the company in terms of financial robustness, you have to try and find some way to bring all of these into alignment. We actually felt that reducing the dividend was going to be part of that, quite frankly. A very difficult decision. As recently as last quarter, I would have said that it would have been something every financial forecast that we had internally for next year and the year thereafter, until about two or three months ago, was not looking at a dividend reduction. We were trying to maintain the dividend.
Clearly, the events of the last two months where the oil price has come up very substantially has led us to believe that that's not sustainable, and we need to make some changes in that direction as well. We booked already EUR 1 billion in Q3 in terms of asset impairments. Q3, you're talking about the middle of December. You're well into quarter four. No, November rather. You're well into quarter four by the time you're doing that. We felt that that was it for the end of the year, that the situation was fully reflected in the balance sheet. Lo and behold, as we get into January and see further deterioration in the oil price, clearly you have to take further changes.
That substantial change in the environment was really what triggered it, and we feel it's a necessary part of maintaining the robustness of the company. Not been an easy decision. It's not one we liked, but we felt it was necessary.
On Russia, I don't want to say too much about Achimov 4/5 because we are not a shareholder right now. Therefore, all I can say is that the production profile I have shown is the profile of a Russian minority authority. What we have seen so far in the due diligence, I would say is not in real conflict with the picture.
What would be important is that, especially Gazprom Dobycha Urengoy, the regional operating company in Gazprom Group, which has all the experience in the development of these reservoirs, that we make this learning curve they have seen in the neighboring block and develop the neighboring block available also for the company, which is going to develop Achimov 4/5. That will be discussed in detail, but I think there is a very good probability that the production profile of the mining authority is also very realistic. Your question on the European Commission, I don't know whether it's in the context of our asset swap or in context of the Nord Stream project.
Asset swap.
Asset swap.
Yes.
First of all, we don't have to ask European Commission whether or not we're going to participate in Achimov 4/5. We have checked whether or not we are in line with all the regulatory framework. We are not in conflict of any sanctions in Russia. We have made all the legal checks, not only once or twice, 1,000 times. We are well-positioned there. As we speak about the assets, we are going to invite Gazprom to be a partner and not defined. I cannot answer your question because it's very theoretical.
Haytham, please. Haytham, next one.
Hi, morning. It's Haytham El-Rashidi from Morgan Stanley. Two questions from me, please. Firstly, if I could just come back to the disposals and your thoughts around asset disposals. I appreciate you probably don't want to give values of specific assets, especially when you're putting these on the market. Could you just give us a sense of the size of a disposal program overall over the next couple of years? Should we be thinking about this as a sort of EUR 200 million-EUR 500 million a year sort of ongoing, or do you think this could be several billion over a number of years, potentially outside of the assets you've mentioned? Related to that, could you just also tell me what the disposals that are assumed in that $55 breakeven as well?
Are you assuming sort of something over and above the ones you've mentioned or not assuming them at all? Second question is around the CapEx. It sounds like EUR 2.4 billion is what you feel comfortable with and consistent with being able to deliver 300,000 barrels a day over the coming years. Is there flex to go a lot lower? It seems like in the charts there isn't. Is that just through choice or is it actually committed spend, you don't really have any more flexibility? Also related to that, what is the underlying decline rates around that sort of EUR 2.4 billion? Are you assuming Romania and Austria decline at a couple of % a year or does that accelerate with that sort of level of spend? Thank you.
All right. Let me start with the disposals. Well, first of all, we just have kicked off the process. To give you an indication about the value of the assets is a bit too early, especially as we speak about Petrol Ofisi. We do, of course, have an idea about what is a kind of a minimum breakeven price as a value, but we have to test the market first before we are going to give you an idea what is it. The disposal program, I think it's a little bit fine-tuned. We will see a positive impact of selling the 49% share of GCA in 2016. I think Petrol Ofisi, at best timing, would kick in 2017. It's really modulating, especially the year 2016, 2017, where we're going to have in our oil price outlook, a real oil price and low oil price environment.
The CapEx standing, as we speak about 2016, most of the CapEx is already committed. The vast majority. That's the reason why I don't see much room of flexibility in 2016. That's also the reason why I made a clear statement that we have done too much CapEx commitment in the past. I would love to see a little bit more flexibility also in 2016. That's also the reason why we have said that we are targeting 2017 as a cash flow breakeven after dividend, because year by year, we are moving down the road towards 2020. The flexibility will go up. Will much go up. In 2016, I would say our flex is not there to go much lower than EUR 2.4 billion. Well, as we speak about the decline rate, I think we have said that we are expecting a production of 300,000 barrels per day on average.
The same production. We will not see a decline in 2016 coming with the additional CapEx cut. What I think Hans will explain later in his presentation that Norway is compensating because Norway will go up a little bit and other regions will go down. In total, the portfolio is given the reduced CapEx spending is more or less constant.
The only significant plan for cash disposal in 2017, which we would expect and hope to complete, would be the Petrol Ofisi activity, that is not reflected in the $55. There are no significant disposals reflected in that target.
Thank you. Hamish?
Thanks very much. I've got one statement, one question. Starting with the statement, I think cutting the dividend was the right thing to do, and I think it's a very prudent thing to do in the current environment. I think we should all be quite pleased not to see another scrip in the market, which leads to further problems in the future. Thank you for that. The question-
Got it.
The question I have is just regarding your EUR 2.4 billion of CapEx. I wondered, and this is easy, if you could let us know if that includes any allowance for what you'll be spending on Achimov in terms of development CapEx. I'm not entirely sure how progressed that is as a project. I know the swap is on sort of negotiations and your due diligence is still ongoing. Could you give us an idea what effect that will have on the CapEx? It's clear to see the volume impact is going to be quite large.
Well, we are optimists here, sitting as an OMV board. We have included the CapEx spending on Achimov and Nord Stream 2 in our budget. It's within the EUR 2.4 billion.
Easy.
Yeah.
Let's move over there, please. In here. Here in the front row. Second row, sorry.
You should move a bit further back in fairness as well, Felix, because.
Sure. Get a drink.
You've been taking.
approved role. Yeah. Yeah. They come up. Everybody has a chance to place his question.
Hi. Good morning.
Hi.
Hello. It's Joshua Stone from Barclays. I've just got two questions, please. One on the asset swap strategy, the second one just following up on the dividend again. I understand this swap with Gazprom would enhance your reserves, lower your cost base. Can you give any indication of what it does to the unit profitability of the upstream? In general, an asset swap strategy as you're employing it, what are you expecting from unit profitability? My second question on the dividend, why did you think one euro per share is the right level? If I look back historically, in the last oil price downs, that's the level we came to for OMV.
Is it right to think going forward that one euro per share is going to be the base level for the dividend, any outperformance on your targets would lead to higher dividends going forward? Thank you.
All right. Your first question on the asset swap will be answered in the presentation of Hans. Yeah. I don't want to give his presentation now, I just ask you to wait for his presentation, and then he will tell you what is the impact on the unit production cost. Okay?
Sorry. What about the unit net income per barrel?
Yeah. He will
Okay
give you that answer.
Okay. Thank you.
It's in his presentation.
I understand. Okay.
I will come to it in my presentation also, if there are some more details to your question.
Yeah.
The majority of the CapEx savings will take place in upstream. We'll give you a detailed presentation on that.
You tell me with complete confidence where the oil price will be. I will tell you with complete confidence where the dividend will be.
Yeah.
Fair enough. Thank you. Let's move back there, please. Matt.
Thanks. Matthew Lofting at Nomura. Two questions if I could please. First, just coming back to your upstream strategy. Could you just talk a little bit about how you see the geopolitical risk profile of the business medium term, and how you manage that? I mean, clearly, the strategy around reserve replacement medium term is more geared to Russia and behind there, areas like Iran. Is the portfolio really deep enough and big enough to absorb that increased risk profile on a medium-term basis? We've seen.
I guess, in the last couple of years, the effects of outages and unexpected changes in Libya and Yemen and other regions. Secondly, just on the balance sheet, can you just clarify when you show the gearing ratio coming back down below 30% for the full year, what treatment are you applying on the hybrid bonds? Which I guess, yeah, that balance has risen to over EUR 2 billion worth on the balance sheet. It looks like under IFRS, you're using 100% equity accounting. How do you really think about that, though, from the perspective of managing the business, given that I would have thought the credit agencies and others tend to apply a 50/50 debt equity treatment? Thanks.
All right. Let me start with your first question on the geopolitical risk. If we look into today's portfolio of OMV, you will find out that about 90% of our production is in geopolitical stable regions. We're talking about Romania, we're talking about Austria, we are talking about North Sea, U.K., Norway. We are talking about New Zealand, which from my point of view is also very stable. Therefore, I think we do have a vast majority of our production in politically stable regions. There's only one issue. Political stability comes with higher costs. In these days, what is the value if I produce in a politically stable region but I can't show a profit?
I think given the fact that we do have such a large share of production and reserves in politically stable regions, there is room left to discuss and to go for production in low-cost regions. If we look into the portfolio, well, we do have the Middle East. I would say it's more security risk we are discussing, which I would rank higher than the political risk right now in Russia. The risk management we do have in place is, of course, that we are going to make an interdependency in place given the swap. On the one-hand side, I will move into that huge reserve position in Russia. On the other hand, I do have a balancing position outside Russia, just in case there's a misunderstanding, which might not come up.
On the other hand, we are talking about just 5% of our CapEx spending in Russia. I'm talking about 90% of our CapEx spending, and that's the capital we use for the future portfolio, will move into politically stable regions. I think a share of 5%-10% we are talking about is really a share we can cover within our portfolio.
I'd like to add something to the risk in our especially upstream business, yeah? Because there are two sides of the coin. The one is the country risk, where Rainer was talking about. Second one is the exploration risk, which we have in our portfolio. Here we will take out substantially a part of the risk, which I will present in my part of the presentation. We will reduce substantially the exploration expenditures on the one hand, and we change the strategy where we want to spend our exploration money. We'll move from high-risk frontier drilling rather to near-field exploration, which is substantially reducing the risk on this exploration business as well. I will come to it more in detail in my presentation.
Thank you, Rainer.
On the hybrids, the treatment of the hybrids, of which we have EUR 2.25 billion in issue, is that they, for IFRS purposes, are treated as equity. So in the calculation of the net debt to equity, they're on the equity side of that calculation. The reason IFRS requires that treatment is that contractually there is no obligation to repay the hybrid bonds. They are subordinated instruments, which is of course why they're more expensive than senior debt, and there is no contractual obligation to repay them. There is, however, a first call option on the side of the issuer to call them back at par and repay them. Of that EUR 2.25 billion, which has been issued in 3 tranches, the first call options are respectively each for EUR 750 million in 2018, 2021, and 2025. So EUR 1.5 billion is relatively long-term.
The way the first call option works is that when the bond is being issued, the investor is really interested in your commitment to actually exercise that first call. So he's basically seeing it as a 7-year instrument or a 6-year instrument and pricing it accordingly. I said when we issued the first one, which was in 2011, that had we had a first call option on a subordinated bond in the fourth quarter of 2008, when liquidity was simply not available anywhere and the market to refinance that instrument, perhaps with another issue of a subordinated bond, simply didn't exist, then I rather doubt we would have exercised that first call because it's the right of the issuer to decide that. The contractual obligation to call it is not given.
Clearly, there's something of an incentive to call it because the pricing changes marginally if you don't exercise that first call. Contractually, you're under no obligation to call it, which of course is why IFRS therefore requires that you treat it as equity. The rating agencies treat it somewhat differently. As you mentioned, the two rating agencies that we have, Moody's and Fitch, give you a 50%, subject to certain conditions, of course, and we ensure that those conditions are applied, give you a 50% equity credit for the bonds that you have in issue. Fitch's treatment would be slightly different, but the two rating agencies that we have apply that treatment.
Thomas, please.
Hi, Thomas Adolff from Credit Suisse. Two questions, please. One on reserve life and the other one just on value over volume. Your reserve life is 9.3 years, the midpoint of your target range. I wondered how much of that is Romania, and what would happen if taxes are raised in Romania. I know it's tough to talk about tax increases when the oil price is low. Secondly.
Reserve life.
Reserve life.
On value over volume, Russian gas and condensate, Iranian oil, UAE oil or sour gas doesn't really sound high margin to me. Especially, I know when you were at Wintershall, you did look at the Achimov formation for many years, but just because I fancy the girl, she's not the right girl. Especially when Russia is up for sale. You can buy something and get one for free. Why is Russian gas and condensate the right thing? Why not oil? It feels to me like you're going into the swap agreement just because you don't have the balance sheet to go directly for bolt-on deals. Thank you.
Rastin, did you have one?
Maybe I take the first question regarding reserve life. Average reserve life is correct, 9.3 years. Romania is exactly on the same level, between nine and 10 years. Which from my point of view is not satisfying right now, especially once you look into it. The three years average reserve replacement rate stands at 73% at the end of 2015. If we look into it, what is the single year reserve replacement rate? We are even below 50. If we continue with that. This is not a sustainable business, we need to change it, and we will change it. I will tell you some ideas how we will change it. That's one, if this answers your question. The second one regarding tax situation in Romania. We are discussing with the government regarding a new tax regime, onshore and offshore.
Especially very important for us also for the new development in the Black Sea, is the offshore tax regime. Unfortunately, there was a change in the government, as you know, because we were close to come to a decision already. Discussions are still ongoing. What we're expecting is that we will come to a final conclusion in the course of this year. This will be implemented with the start of 2017. A new tax regime for Romania, onshore and offshore.
On your question on Russia. First of all, the net profit will be determined when we are going to sign the contractual agreements. What are the price levels of condensate and gas? It's too early to give you an idea about the net profit or the margins we are going to generate there. Why is it so attractive for us? Especially that I get also margin in the positive or net profit in times of a low oil price. That's where we are going to focus on. My experience in Russia, with building a business is very easy. If you go to Russia, you need to find the right partner. It's not that you have to find the right oil or gas field, yet there are so many fields you can fall in love easily.
You need to find the right partner. That's why we have designed this project as an integrated partnership with Gazprom along the entire value chain. What we have said is What I'm talking about is just risk management. I'm not choosing one of the oligarchs. I'm choosing a partner we do know since 48 years. I will not only participate in the upstream sector. That's the reason why I also like to have a gas component, because we are going to invest both together in expert capacities. I will bring the gas into my home market, Austria. It's really a cooperation along the entire value chain. Looking into Russia, well, there are so many attractive potential partners, but I have chosen one 48 years ago, and I will go that a long line. In oil, I haven't found anybody right now.
I just picked the opportunity when it knocked at the door.
Geologically, Achimov formation is fully de-risked. You're very comfortable?
Absolutely.
Thank you.
To your point also about doing it as a swap just because of the balance sheet. I don't think there's an oil and gas company on the planet when they had the opportunity to acquire something and wouldn't prefer to actually swap it with assets that they currently have in this environment. We're quite pleased with that structure, frankly.
Henry, please.
Sure.
Oh, it's you.
Good morning. I'm Patrick from UBS. A few questions on Russia as well. The first one on the Nord Stream 2. Can you remind us of the timeline in terms of getting approval from the EU, and how confident you are of getting this approval? Secondly, if you were not to get the approval for Nord Stream 2 for some reason, does that have any implication for your asset swap with Gazprom or is that completely separate? Finally, perhaps going back to the previous questions, are you able to give us a rough idea of the kind of returns you would get from this asset from Achimov? Thank you.
Your last question, say again.
What kind of return you would get from Achimov?
Return. Okay. All right. I take all your questions. The timeline Nord Stream 2 is, first of all, we don't have to ask an approval from the European Commission. What we have to do is we have to build a pipeline like Nord Stream 1, and we have to ask for the approval for all the countries where we are going to build the line. We have to go to Finland, for example, we have to go to Germany and ask for these approval to build the pipeline. The permits, the construction permits. The second issue is that the timeline is very tough. We need to have the FID on Nord Stream during the year 2016, and then it will run into commitments already into pipeline orders, into booking of laying barges and so on.
It will already start in 2016, and we are just waiting the merger control clearance to farm into the project company. The timeline is end of 2019, both lines are going to be in operation. It's a tough job, but the management of Nord Stream 1 company is doing also the job of Nord Stream 2 company, and they have convinced us that they can do the job and that they can keep the timeline. I'm very optimistic. Your question about the implication of the asset swap. Well, first of all, we have to wait and see.
We have to wait and see. In both parts, I am optimistic. I'm an optimist. The asset swap, I really have to put into place so that we agree on the assets we are going to swap. We were in a very early stage. I am very optimistic as we speak about Nord Stream 2. It's a very good project, and I think we have already decided because we have signed our participation in the project. We are just waiting the merger clearance, and there is no sign that the merger clearance will not come. That's the reason why I think my scenario is clear. With a very high probability, I will participate in Nord Stream 2, therefore, I don't have to discuss any implication on the asset swap. As we speak about the return of Achimov, I have to repeat myself.
I can calculate the return when I have fixed the contractual terms on especially the prices for gas and for condensate. We haven't done that yet, and therefore, I can't give you an idea. What I can tell you is, each investment project, it doesn't matter where it is, has to surpass a certain threshold to get a green light from the OMV board. Also Achimov 4/5 has to surpass that threshold.
Tamás, please.
Tamás Pletser from Erste Bank. I got three questions. First of all, your Russian strategy. Would you give some expertise also to OMV, or would you act more as a financial investor with this asset swap? My second question is, also, can you shed a little bit more light on the rationale of Nord Stream 2? What I see in the European gas market that it's falling like a stone. It's down 20% in the last four, five years, the consumption level. Nord Stream 1 is not utilized, as I know, and it has also some problems with the Third Energy Package of Europe. What is your optimism based on Nord Stream 2 that you want to spend EUR 1 billion cash from your balance sheet? My third question is regarding the Black Sea developments.
Do you see any rationale to invest into Black Sea exploration and development at the current Romanian gas prices? Thank you.
All right. I take Russia and Nord Stream, and my colleague, Hans, will talk about the Black Sea. Well, first of all, let me talk about the rationale of Nord Stream 2. First of all, the utilization of Nord Stream 1 is just below 100% because of the remedy which has been set by the European Commission. The investors of Nord Stream 1 are in negotiations with the commission, I'm very optimistic that this blockage of capacity utilization will disappear because it's in the interest of Europe and it's in the interest of the shareholders because the capacity is needed. If this remedy sets, when we have asked for an exemption from regulation for Nord Stream 1, the pipeline will be utilized on 100% basis. Point 1. Point 2, first of all, we will not put EUR 1 billion from our balance sheet.
As I said, it's an equity of 30%, which will run into that. Why is it, for us, an attractive investment? Because we don't have that risk you have associated to us. We're investing there, we're going to build that pipeline, and we have sold the capacity. I don't care whether or not the market is asking for this gas or not. We don't have a volume and a marketing risk coming with that project. What is the rationale of Nord Stream 2? Nord Stream 2, what we do see is, of course, a stagnation of the European gas markets. I agree with you. There is a little bit of an upside if power generation might come back. What is important for that pipeline is the question of import needs.
What we see is that we do have a further decline of domestic gas production in Europe. We cannot frack in Europe, therefore, we will not go for a shale gas potential, and we do know very well the reservoirs in Europe. There is no upside. Europe, the European gas market, needs to import more gas to be balanced. That's targeting Nord Stream 2. What I have seen is that especially in the Netherlands, they have a strong need for additional gas because they are cutting down the production in the Groningen field. I think the pipeline, first of all, there is an additional market behind that. The second is, of course, our interest. It comes with much higher transit security. This transit line via the Ukraine, we are used to.
We know that it's not comparable to the transit security we are going to see via Nord Stream 2. That's the reason why I think I'm responsible for the security of supply in Europe and not in the Ukraine, to be quite clear. That's the reason why we are supporting the project, because it will improve the security of supply. The question on our participation in Achimov 4/5. On the first look, you might say we are a financial investor. Given the corporate governments we have to negotiate, we will take care that we participate also in the development of the field. It will be a quick run into our technological competence that OMV will be one of the few companies with an experience also to drill wells and to develop production in permafrost regions. That's something what we are gaining.
We will participate in the development because we do have pretty good geologists, and they will understand the reservoir. We have the chance and the room that we can bring in our ideas how to develop what kind of wells are we going to drill there. Are they semi-horizontal? Are they totally horizontal? Are they vertical? All this stuff we can do, and we will take care that OMV know how will be also reflected in the development. What I can say is, Gazprom is very eager to get fresh knowledge into their Achimov development, because especially what we have seen in their cooperation with other partners, in partnerships, they have done a pretty good job. I wouldn't call OMV a pure financial investor. We have a chance to design the project, how we are going to spend the money.
What I can say, ExxonMobil and OMV, we are committed to this project. We are committed to develop the Black Sea in Romania. We have just finalized the second drilling campaign, which we have started in 2014. We drilled seven wells. Most of them encountered hydrocarbons. Regarding the gas price, gas price in Romania is almost similar, what we see right now in Europe. Also the gas, it depends then on the market situation, when the first gas will come on stream, which we expect right now beyond 2020. What we know right now, we give priority to the Romanian gas demand and Moldavian gas demand. The rest will be sold in the region or elsewhere. We will have maybe a different price regime.
Second one, the gas price is not the only factor which is determining whether this is an economic project or not. What we are doing right now, I see four main criteria which will decide at the end whether we have an economic project and whether we will pursue to develop the Black Sea potential, which is yes, which is the gas price. On the other hand, it's the volumes which we have discovered, and that's what we are evaluating right now. We are looking into it, into the data which we got from the wells we have been drilling. What are the final volumes? Second, the investments. The engineering just starts right now. To get the costs down, you can a lot do on the engineering side to make this project more economic.
The third one, besides the gas price or the first one, is the tax regime, as I mentioned before. I think these are the four main criteria whether a project is economic, yes or no. We are working on all of them, I would say the gas price at a given time is a given price there, we will see when it comes to final investment decision what we expect right now in two years from now, so in 2018. We will make the final decision whether we will develop the potential in the Black Sea, yes or no. Right now, we are quite optimistic on that.
Christian, in the back.
Thank you. It is Michael Alsford from Citi. I have a couple of questions on the kind of longer-term plans on the upstream business. You are clearly focusing around value over volume. Can you maybe talk about your criteria around reinvestment? What are your hurdle rates? What are you thinking about when you do reinvest? Is it typically IRR? Is it cash margins? More broadly than that, when you look at the kind of long run CapEx assumptions that you have pointed to today, do you think that is sufficient to deliver that sustaining business in the upstream, or do you think that will actually have to go up when you start to get towards 2017, 2018? Thank you.
I will take the first one regarding hurdle rates, economic hurdle rates. What we are using in the upstream business is a 15% rate of return. Projects which are not meeting those hurdle rates, 15%, we will not implement.
Given the fact that we have reduced our CapEx spending, I think given our current portfolio, we need to have that level of CapEx spending if we do not want to see a decline in our production. It is more or less the break-even. There is not too much room left for us to breathe. If we go below that, we will ask ourselves, what kind of priorities are we going to set? As we speak about the sustainability of a reserve base, I think I have explained clearly that in 2016, we can manage our reserve replenishment if we are successful. It depends. In 2017, we will close the transaction. It will kick into our production. As to speak about the reserve base, I feel comfortable.
It is not depending on my CapEx spending. It gives me the room to reduce the exploration and appraisal activities. If this opportunity will not knock at our door, we will not successfully catch the opportunity. We have to rethink our replenishment strategy again, if we can find a satisfactory plan. As we speak about CapEx spending on production, we have two kinds of issues. First of all, it is a fight against decline because of the high maturity. Our mid to long-term concept is that we would like to bring in fresh production, where we do have a longer lasting production platform. The production profile I have shown you on Achimov-4, 5 is just bringing in the stability of production, so that I am not getting tired too much using lots of CapEx to fight against the decline.
Oh, sorry.
Hi, it's James Thompson from J.P. Morgan. Just a quick question about your reserve replacement ratio. You're targeting 100%. If I look at that over the next five years, could you just perhaps break down for me what percentage of that will come from net acquisitions, what percentage from revisions of your base production assets, and what percentage are you expecting from your exploration activities?
Thanks, Marcus. Well, as we speak about the reserve replenishment, in our strategy, the minimum of 100% comes by acquisition with the asset swap transaction. Everything on top, as we speak about revisions, exploration, and so on, is on top of the 100%. The exploration, I think there is a number of 50, or what have you said?
It was below 50 in one year. Exploration reserves replacement rate in 2015 is below 50.
Yeah
single year.
Yeah. This will be a growth of our reserve base. Yeah? 100% of the reserve replenishment with the transaction will come with the Achimov 4/5 participation of OMV, and a growth of our reserve base will come with all the other activities.
Any other questions?
Sorry. I will come to it more in detail in my presentation, where the reserves replacement rate in the future should come from. Yeah? There's a slide on it, and I will present it then.
Yeah. I have a follow-up question on the taxation change in Romania. From what I understand, Romania already increased, in fact, the taxation those last years by, for example, putting a special tax on natural gas price increase, construction tax as well. From what I understand, all the taxation system will be changed and the final impact, post taxation change beginning 2017, will be relatively low, in terms of cash for you, meaning that the return of your Romanian production should remain roughly the same. I just wanted to know if you share this view or if you expect a real increase in taxation in Romania from the current level. As well, when we look at Petrom results this quarter, negative for the first time, it looks like it is a bit difficult to materially increase the taxation in the country. The other question regards with the working capital.
You've said that the free cash flow breakeven or the cash, sorry, the oil breakeven was $70 per barrel in 2015. Does it include the $400 million working capital increase? Can you please just come back on the increase in the working capital, whereas the oil price is declining? What we should expect in 2016, 2017, in terms of working capital movements, if the oil price starts going up? Thank you.
The $70 does include that increase in working capital that we had this year. What it means for the year that we're now in, 2016, clearly the price has deteriorated still further, there's a risk that we may also have to swallow some of that. We're looking at that right now, clearly. It's an unusual situation to find the price of a commodity coming down, causing your working capital to come up. Because we've been able to leverage our suppliers into financing us so much that unfortunately as a consequence of that, the corollary of the whole thing, of course, is if the oil price increases, we should actually see the working capital benefit of that being positive. It will have an impact.
Nothing like the impact it had last year, because clearly we've halved the oil price 2014 into 2015, hopefully we're not going to see a further halving of the oil price going in from 2015 to 2016. That's certainly not what we're planning on. On the taxes in Romania, the construction tax, I think, has been around for several years right now. Clearly, as one of the major investors in Romania, we've been disproportionately hard hit by that. The increase, however, in taxation in terms of natural gas was something we also benefited from, because what that actually meant was as the cake got bigger and the gas price was being liberalized and increasing as a consequence, because although gas prices in Europe are under pressure, the Romanian prices increased quite substantially over the last four or five years. We shared that with the Romanian state.
Roughly speaking, I think it was about 60% for them, 40% for us, or 55/45, something of that nature. Although there was a tax on the increase in the gas price, we got almost half of that. Where the future will take us, we don't yet know. There is a consulting process which has been announced. There's been some discussions and rumors in the media that they will move to some sort of profit-based tax. There's nothing certain on that at that point in time. Clearly, we'll take part in the consulting process. One thing that governments, and the governments have changed quite frequently, unfortunately, during this particular period, but a consistent statement that the governments have always made, and we've been obviously pushing on this, is that this industry needs investment, and the investment will come from the cash flow that it generates rather than from the clouds.
If the company isn't able to generate sufficient cash to allow that, it will have consequences, clearly, and that's fully understood. They want an industry that invests in Romania, and we'd like to be part of that, but the business needs to be able to support that.
I would like to add something regarding construction tax. You know the construction tax was issued some years ago with 1.5%. This was reduced in 2015 down to 1%. This is already the first step in the right direction. As David mentioned, it's too early to speculate what will be the final result. We need to wait until the discussions with the government have been finalized.
Thank you, gentlemen.
Maybe one idea on the further information on the working capital at the end of 2015. We will be having is a turnaround in the Schwechat refinery in the first quarter starting 2016, and this is the reason why we have built up inventory in order to keep our sales stable there, first of all. Second of all, if you look into the forward curve of crude and products as well, there are some contango deals that we have been undertaking, obviously, which are highly profitable at this point in time. This means that this will not be the same at the end of 2016 then.
Thank you, gentlemen. Let's now take a break. We'll be back after lunch at 1:30. Then listen to the presentations of Mr. Pleininger and Mr. Leitner and have a further extended Q&A session. Thank you.
Thanks.
Thank you. One, two.
Yes.
No, it's your show. It's fine. Good afternoon, ladies and gentlemen. Are you ready? Yeah. Let's start. Good afternoon, ladies and gentlemen, welcome to the second part of our strategy update. I will talk about upstream. Then Manfred Leitner afterwards will talk about more details on the downstream strategy. By the way, what you see here on the picture, that's a offshore platform in New Zealand, Maari. Some of you know me from previous roadshows, some maybe not. I am in this position since September last year. I'm half a year heading the upstream business in OMV Group. I'm new in this position, relatively new, I'm not new to the company. I'm already with OMV since 39 years, 39 years in the upstream business. Talking about some key figures in upstream.
As you have seen already, EBIT was clearly influenced and impacted by the sharp drop of the oil and gas price in the meantime, and secondly, by the shortcoming of Libya and Yemen. As you know, Libya was shut in in 2014 already, and Yemen was shut in in April 2015. Regarding production, you see quite stable production despite the shortcoming of Libya and Yemen, where we are missing 30,000-40,000 BOE per day. This was compensated by the increase in production of our Norway assets. Reserves replacement rates. What you see there is the development of our 1P, of our proven reserves. You see already Oops. In the last two years, 2014, 2015, a decline of our proven reserves, which is in the long term, not a sustainable business. As I mentioned already, reserve life end of 2015 stood at 9.3 years.
Reserve replacement rate on proven reserves, three years average, stands right now at 73%, and on a one-year basis, it is even below 50. This is not sustainable. That is something we are going to change, and we will change it. Key priorities. As you know, in our business, especially in the Upstream business, HSSE remains one of our key priorities. Safety, security of our people comes first. Cash management. Cash was mentioned already. Cash is king, especially in times where we have a low oil price and the low gas price. That is why we introduced a rigorous spending discipline on CapEx, OpEx, and exploration and appraisal expenditures. I will show you in a minute what we have done already and what we will do in the upcoming year. Portfolio, we have to focus.
We will focus on three core areas and on selected development areas, namely Russia, UAE, and Iran. Reserves replacement, reserves replenishment. Our clear target is to achieve 100%, and I will come to it, how we want to achieve it until 2020. We will focus with our acquisitions on low-cost areas, low-cost regions, and we will reduce our risk exposure in our exploration portfolio in how we want to do it, rather focusing on near-field exploration rather than on high-risk frontier drilling as we did in the past. Maybe giving you an example, on deepwater offshore drilling, developed and discovered-- Not developed, sorry. Discovered resources per year declined from 2010 until 2014 by 75% in deepwater offshore areas. 75% less discovered resources on a yearly basis in this business is also one reason why we are walking away from this high-risk strategy.
Strategic partnerships was already mentioned. We will build on those ones which we have in place, which is a good cooperation with ExxonMobil in the Black Sea, but also with Repsol, deep onshore Romania, but also with Statoil in the North Sea and in the future, Gazprom, ADNOC, Mubadala, NOC, name it. Cash management. What have been achieved already. Here I think you see good results already, what we have been doing in 2015 compared to 2014. We reduced our capital expenditure from EUR 2.7 billion to EUR 1.9 billion. In 2016, we are targeting EUR 1.5 billion, and 2017, 2018 depends also very much on the development of the oil price. Our exploration expenditures came down from EUR 700 million, roughly EUR 700 million in 2014 by EUR 100 million in 2015, will be reduced to EUR 450 million in 2016, and we aim to get down to EUR 300 million in 2017-2018.
Production costs also quite successfully reduced. Our target is to reduce it compared to 2014 by 20%. As an upside potential, we see if Libya would come on stream, this would mean another more than EUR 1 cost reduction on a BOE basis. In total, we improved our cost position in 2015 by EUR 1 billion, EUR 800 million on investments, EUR 100 million on E&A expenditures, and roughly EUR 100 million on OpEx. How did we succeed that? As I said, OpEx savings in the amount of EUR 90 million. Headcount was reduced by 9%. This was not only done in Romania, this was worldwide. Only two-thirds were done in Romania, but more than 80% of our staff is located in Romania. We did more in the international business as we have done in Romania.
Office costs, this is in G&A approximately, we reduced by 12%. Number of wells came down from 160 wells per year to 110 wells in 2015, which is a reduction of around 30%. Portfolio focus, as Rainer mentioned already, we are focusing on three core areas and selected development areas. Core areas, core number 1, Romania, Austria, core number 2, North Sea, and core number 3, Middle East and Africa. Core regions should be self-funded. I can tell you already right now, Romania, Austria is already self-funded. The North Sea will be self-funded in two to three years once the major investments are done, like Aasta Hansteen and Schiehallion. Core number 3 will be self-funding once Libya is coming on stream. Starting with more details on the regions. Core number 1, Romania, Austria. What is the key challenge there?
The key challenge is beating the decline at reasonable costs. This is also based on our value over volume principle. What you can see, production in Romania, we kept quite stable over the last years. Remember in the Strategy 2011, what we have announced there, we want to keep the production in CEE above 200,000 barrels per day until 2014. We achieved this until 2016, but now with all the cost cuttings and also invest cuts, we have to go down, and what we are targeting is a production and stabilize the production at 190,000 to 200,000 BOE per day. We expect a 4% decline if the oil price stays at very low levels. Also here, a reasonable achievement on OpEx savings. We cut the OpEx down by 23%, from $16 per BOE down to $12.
We will continue that performance, what you have to keep in mind, we are talking about mature assets, it's not so easy to drive this further down. We'll do it. How we want to do it? We'll further drive operational excellence and design value. What I can tell you, give you an example on operational excellence, what we are doing, we are exchanging knowhow between the countries, what was very successfully implemented. For example, we sent work over crews from Romania to Austria. They were working there half a year, and the experience which they made there, they came back to Romania and implemented the learnings. What I can tell you is they got an efficiency improvement by 20%-30%. That's what we are rolling now out in a bigger scale, also in other parts of the business. Applying state-of-the-art technology, mainly EOR.
We have a pilot project running now in Austria together with Statoil, Total. Gazprom Neft is also very much interested in it. I think we are the frontrunners on this topic, we'll see. I got good results already last week, so we will announce it once we are there. The issue there is regarding polymer flooding to make it economic, also at a very low oil price, because it's more costly than the normal water flooding or steam flooding. Exploration, near existing infrastructure, that what we always did in Romania and Austria, we'll continue that. I see still big potential in Romania. Just as an example, in Romania, there have been drilled around 65,000 wells in total up to now, but not more than 300 wells deeper than 3,500 or 4,000 meters. Still potential what we see there.
One reasonable example is Totea, which we have discovered some four-and-a-half years ago, which is still on stream and producing 15,000 BOE per day, is half of the production in Austria and more production as we produce in some of our countries. Explore and develop the Black Sea potential, also one of the key targets in Romania. Some words to Neptun Black Sea development. There was already a question about it, I repeat. We had a Domino discovery in February 2012. We discovered a volume estimated at that point in time of 42 to 84 billion cubic meters. We are still committed and confirm those volumes. We have been drilling around seven wells, in the drilling program 2014, 2015, we finish this program January 2016.
As I said, we discovered hydrocarbons in most of the wells, now we are working on the economics of the Black Sea development in Neptun. As I mentioned, it depends not only on the volume, it's the volumes, it's the tax regime, it's the gas price, and it's the CapEx. Coming to North Sea. Here, the major projects are ongoing. There are three big projects which should be mentioned. It's Edvard Grieg. We came on stream with Edvard Grieg end of 2015. Schiehallion will come on stream 2017 Aasta Hansteen in Norway, 2018. With the support from those projects, we aim to ramp up the production up to 70,000, 80,000 BOE per day. What you see on the other side, with the ramp-up of production, we'll see a decline on production costs per BOE as well.
What we are doing as well, especially in this oil price environment where we are right now, we review our exploration activities in these areas, especially in the remote areas of the North Sea. This is west of Shetland, west of Britain, Barents Sea. We're looking into it. We have a close look into it, whether those projects like Rosebank, Cambo are still economic at a low oil price environment. Quarter three. Middle East, Africa, we have one key project ongoing there. This is in Tunisia, Nawara. We had to delay first gas from 2017, this was announced last time, to 2018 due to some technical problems. Also we shifted willingly some of the investments. 2018 is the expected date where we will have first gas. What you see here as well is the impact of Libya and Yemen.
If Libya and Yemen would be on stream, we would be close to 60,000 BOE per day in 2017, 2018. You see also the upside of the production costs, which is in the amount of around EUR 7 per BOE, which means if Libya, mainly Libya, would be on stream, we would see EUR 7 per BOE, an improvement on the production costs. For sure, we will develop the growth opportunities in Middle East, also one of the key targets, mainly in UAE and Iran. What we are doing there, you see, we have two projects ongoing in UAE. This is Shuwaihat, where we will drill the next exploration well 2Q, 3Q. We will spot the next well.
The exploration activity agreement with ADNOC in East Abu Dhabi area, which is here, we'll spot the first exploration well in the second half of this year, and we're discussing right now with ADNOC and Oxy the technical evaluation agreement regarding the northwest offshore Abu Dhabi area, where some interesting fields are located there. In Iran, we work on a new portfolio there. We build on the experience, on the relationships which we build up prior to the sanctions. We have here where we are focusing two fields where we have been involved already before. This is Band-e Karkheh. This is a green field development where we had a discovery some years ago.
This is the redevelopment of Cheshmeh Khosh field, which is an old field already, discovered in the 1960s, which is currently producing around 50,000 BOE per day, and we see some good potential to ramp up the production there. We are discussing a joint study agreement in the Fars area, which is in the southern part of Iran, which is half is onshore and half is offshore. Coming to reserves replacement, reserves replenishment. What we have right now is proven reserves in the amount of 1 billion, 28 million BOE proven reserves end of 2015. With the current portfolio we have right now, we will lose until 2020, roughly 300 million BOE, which could not be replaced. How we want to do it? We want to do it with acquisition in low-cost areas, like in Russia, in the Urengoy area.
We'll come to it with more details, how much this could add on the reserves to our portfolio. 200 million-250 million BOE should come from acquisitions until 2020. New field exploration should contribute with 50 million up to 100 million BOE, and from IOR, EOR measures, we expect up to 50 million BOE so that we can close the gap until 2020, so that in 2020 we'll hopefully we can then announce that we still stay with our proven reserves above 1 billion BOE. Achimov. We'll show you that Achimov would really have a significant impact on our portfolio, a significant positive impact on our portfolio. What can this do to us? On the one hand, it would deliver stable production for the next 20, up to 30, even more, 30 years in the amount of 20%-25% of the current production, what we have.
What we estimate is that two-thirds of the production will be gas and around one-third condensate. We would have access to additional reserves in the amount of 600 million BOE, and this is compared to the 1 billion where we stand right now. This is adding more than 50% with one acquisition, which we can do, and it's 5 times the production what we have been producing in 2015. Five times only with this project, we would achieve 5 years, 100% reserves replacement rate only from this single project. This would sort out our problems, I think, for the next five, seven, eight years because there will be some additional reserves coming also from the other countries. This was also one question, what would Achimov do to our cost position?
It would reduce the production cost for the entire portfolio up to $1.5 USD per BOE. $1 improvement could come from Libya on stream and another $1.5 from Achimov. Then you can think about it, where we would be and compared with the assets where we have that the majority is from mature assets, I think we would be world-class with those production costs per BOE. As I mentioned already, we will reduce the risk exposure on our exploration portfolio. We'll cut down the exploration and appraisal expenditures by 60% from around 700 million down to 300 million in 2017, 2018. This is a change in our strategy. We move away from the high risk, long lead frontier drilling to more near field, short-term, low-risk exploration. This would also change substantially the cycle times of our projects.
As an example, Neptun, I signed the contract with ExxonMobil. It was November 2008, if I'm not completely wrong. First gas, we will see beyond 2020, around 10 to 15 years. You have to wait until you get the money back what you have invested. With near field exploration, also one example from Romania, like Totea, we discovered the field, and we brought the field on stream in record time with less than one year. Within one year, you get already cash in, and this is also here part of our strategy that we reduce substantially the cycle time from 10, 15 years, which you can get from this high risk, deep water onshore, projects, which you can get from projects in near field in where you have an existing infrastructure. This doesn't mean that we don't drill any offshore well anymore. Yeah.
I really want to say this. We keep committed to Black Sea. We keep committed to the North Sea because we have there some producing areas in or nearby existing infrastructure. As you see, there's quite a big different how fast you get the cash in, whether you drill a well in frontier areas or whether you drill it in near field, near existing infrastructure. Production guidance, 360,000 BOE per day is our clear target for 2020. As you can see, decline in the mature or in the existing assets is replaced by the key development projects, which will come on stream until 2018. This is Nawara in 2018. This is Schiehallion in 2017, and this is Aasta Hansteen in 2018. The upside, as Rainer mentioned already, will come once Libya and Yemen is fully on stream, but mainly from our engagement in Russia.
What's not included here is the deep onshore potential in Romania. As I mentioned, Totea, 15,000 BOE per day. If we have once more such a discovery, and that's what we are aiming for, then this would be on top of the volume, which is mentioned there. Summarizing once more, top priority, cash management, cost management, portfolio focus. We'll focus on our three core areas and our selected development areas. Reserve replacement rate, clear target, 100%. We need to achieve in order to have a sustainable business until 2020. We will continue, and this will be supported by strategic partnerships. I think we have developed and created a sustainable and a strong upstream strategy, which reflects, on the one hand, the current environment, oil price, and gas price environment, but which is also based on clear and realistic targets, which can and will be achieved until 2020.
Thank you very much for your time. I think it's Manfred, it's you.
Good afternoon as well from my side. OMV Downstream. I know that Downstream usually is not the primary focus of the financial community, but as well you have seen, if you look into 2015, the decisive importance for the OMV Group. Just to start with, the OMV Downstream division is new since the 1st of January 2015, because then it was decided that Downstream Oil part and Downstream Gas part would be combined under one leadership. What I would like to show you here is where we are in terms of positioning of the two different business segments.
If you look into Downstream Oil, I have started the restructuring of the business in 2011, we have depicted here just indicatively the cash flow contribution, that free cash flow after investment that's readily available for investment into other divisions if you want, and for dividend. As well, the return on capital. The return on capital has increased in the meantime fourfold. Downstream Gas is at the beginning of the restructuring. We have not done a lot, obviously, in the past. What you see here is we have been cash neutral, I would call it more or less, and with a return that is declining. These are two fundamentally different sides of a coin. Here we have made the homework to the large extent, and here we are having the homework in front of us. Downstream Oil.
This is a slide I like very much because we have not produced it ourselves. I just took it out of the Barclays quarterly benchmarks. If you look on the right side here, what you see is I always take the wrong button. The green one is OMV Downstream Oil ROSI. The dark gray one is the ROSI of our European peers. The dotted line here is the ROSI of the integrated international majors. What we have obviously done, just a few observations here, two or three. First of all, we have started at the level of the European peers, what you see is that we have built up over time a superior premium on the European ROSI level that we have kept all over the time.
Interestingly enough, if you look into 2015, it looks like it has gone down to a certain extent, which is logic, because in times when the refining margins and the petrochemical margins are at their maximum, it's very easy as well to earn money with less efficient refineries. During times when the refining margins are low, then you clearly see our competitive disadvantage here. How we came to that? I have restructured the assets. We have 27% less capital tied up in the business. This comes from divestments, and you know all of them. This comes as well from concentration reducing the net working capital, which we have done over time quite successfully.
The OpEx had been reduced on a unit level by 17%, and as well, Borealis contributed increasingly well, and we have a 92% increase in the Borealis contribution to the OMV downstream result in terms of share in the net income. Behind all of that is obviously an organization that we have defined in a way that the integrated margin from the crude supply to the sales of the products is managed in the most effective way. This is the cash flow contribution over time. You see here in 2013, obviously, divestments and the focus on the reduction of net working capital. The only remark here is that on average, it is approximately EUR 0.7 billion over the last five years, four or five years on average. This is something which clearly comes not because of the refining margins only because I've shown them here.
They are very much different, the cash flow and the free cash flow that is coming out of Downstream Oil is pretty reliable and in a good level. What is the outlook for the midterm European oil downstream development? 2015 was a very, very good year, and obviously, we have recorded record results. Borealis has recorded record results. This is something which is most probably unique. Two things. One is the oil price, because the low oil price obviously is helping refining operations. At the same time, the low oil price has obviously a positive impact on demand. Product demand has gone up quite dramatically last year on a global basis. For instance, gasoline demand in the U.S. grew by 5% approximately.
If you know that the gasoline demand of the U.S. is approximately close to 50%, maybe 47% of the global gasoline demand, then you know that this is an increase of 2.5%, which is huge. The refining industry was just not prepared for such a demand increase because this was something where you reduce the capacities and inventories over time, and that's the reason why the refining margins have rocketed. This does not mean that the structural overcapacities in the European market are away. They are here. They are even now operating again. Would have been even better if you see in the mid to long term to have lower refining margins, because last year incentivized a lot of less efficient refineries to come up again and to start operations again. It will take some time to get the picture turning around again.
From 2011 to 2014, approximately 8% of the European refining capacity has been taken out of the market, has been closed forever. What you see as well, until 2020, we believe that the product demand will go down even further. This will mean that from now to 2020, another 10% will be at least under risk and most probably, a bunch of that refining sector will have to go out of the market because we'll not be in a position to operate profitably. The strongest decline here is obviously the heavy fuel oil, which we believe will go down by a quarter, and gasoline in Europe, not globally, but in Europe, where we see another 15% decline. Our refineries, having a strong integration, either in upstream and/or in petrochemical part of refining, I will come to that later.
We are well-prepared for that, and we are working on that to be in a position even to survive and to beat the others in a more hostile environment. The restructuring process here has resulted, and this was the final ultimate target anyway, in a superior integration of the assets. I think the main KPI, if you have integrated refining and marketing business, is how you can use the capacity of your refineries. This is finally the ultimate comparison. If you look here, that's the result of what is shown here. We are actually. This is the European average always. What you clearly see is that we are very much ahead of the pack. We are even leading the industry in terms of refining capacity utilization. Last quarter, 2015 was for 94%. The average over the year was 93%.
You can have high refining margins, but only if you have a high capacity utilization, you can transfer those refining margins in your accounts, in your cash deposits. There are three distinct areas where we have an integration and we have developed an integration and we'll continue to do so that is giving us USP against our peers. First of all is the integration into upstream. If you look into the Petrobrazi refinery in Romania, where we have finalized the modernization program at the end of 2014, we produce or we process 100% of the upstream production of Petrom in that refinery. In Austria, we are taking 10% of the domestic production, so 100% of the domestic production to Schwechat Refinery, and this is 10% of the crude we are processing there. Why is that important? It is important because it's a big difference.
If you have the crude production in the vicinity of your refineries with very low transportation cost compared to going to the world market to have a long delay and a long planning horizon in front of you. You are not in a position to optimize in the same way as you get the crude on a daily basis into the refinery, and you build up the refinery exactly on the qualities as well. The second one, I've repeatedly mentioned that in the past, is a stable retail sales performance. Which means retail, so the sale of gasoline and diesel over filling stations is the most reliable sales channel you can imagine. Very easy to plan. There is maybe 1% or 2% or 3% planning deviation, or the actual deviate in such a low percentage from the plans.
This is exactly the best background for a refining operation, because then you can run the Refinery in a very stable mode, and you do not have to wait until your sales guys are having the success to have another customer found, big customer found or not. We are running very stable here because we have a 32% integration. That means that 32% of our refinery capacity are sold via retail. Our peers are at 23%. The third one is the petrochemical part of refining. The Schwechat Refinery and the Burghausen Refinery are petrochemically integrated. Burghausen is not even producing a single unit of gasoline. We take the whole naphtha stream, which is the feedstock for either producing gasoline or bringing it into the petrochemical part of refining into petrochemicals there.
As you recall, the gasoline part is the one that will go down in demand most. This will be the challenge for the other refineries that are not integrated here. We are having a 13% integration. 13% of capacity is going to petrochemical part of refining, and only 6% are with our peers. This resides in this best of class utilization of the OMV refineries. Coming to retail shortly. What have we done in retail? Where are we there? We have worked on the optimal brand positioning, first of all. What we have done is not only OMV and VIVA is a brand offered to our customers, it's two brands. Why? Because in the countries where we have the refineries, our home markets, Austria and Romania, we would like to cover as much of the customer segments as possible.
The OMV VIVA is the offer for the premium products and for the high-quality looking customers, convenience. Then we have introduced Avanti, the new brand, which is an unmanned filling station. Very low cost, very low investment, and as well, very low prices. This is for the price-sensitive customers. That's exactly supporting the logic to sell as much as possible out of our refinery production of Schwechat Refinery, in that case in Schwechat, into the Austrian market. The same concept we have applied in Romania, where OMV is the quality offer and Petrom is the value for money offer. We have developed premium product offer in our new brand, MaxxMotion, which is having a much higher margin behind. That's the reason why we actually have a higher margin, and a higher EBIT nowadays.
One of the reasons, if you look here from 2013 to 2015, the EBIT per filling station has gone up by 30%. The throughput, by the way, has been gone up by 15%. All of that brings a higher integration of the businesses refining and sales via retail. Very shortly to the petrochemical products. I have mentioned that, and I will call it here the superior alternative to gasoline, because the alternative would be to produce gasoline. Gasoline is not easy to be sold in Europe in a declining market. If you take the petrochemical products that we have sold over time, you see that there is a EUR 3 per barrel higher refining margin that is coming on top of our fuel refining margin, and this is the OMV Indicator Margin. The OMV Indicator Margin that we are always showing in our quarterly reports is the blue one.
This is the additional margin on a refining margin basis that is coming out of our petrochemical operations. Therefore, this is such an important part of it. You have heard that we have, in the meantime, been successfully prolonging the contract with Borealis in Burghausen and in Schwechat until 2028. We will have a long-term stability to keeping that business in the same profitability. Borealis itself, if you see over time, Borealis has done a very good job. One of the big points there behind that is, of course, Borouge. Borouge has come on stream 2015, apart from one sophisticated polyethylene unit, which will come on stream in 2016.
When that unit is in place, this will come very soon, this will be the 2.5 million tons increase to the existing 2 million tons to 4.5 million tons of polyethylene production capacity, the biggest polyethylene production site in the world. Petrol Ofisi. You have heard the reasons why we have defined Petrol Ofisi as a divestment target. It is clearly not in the center of the Downstream Oil strategy because as you heard already, integration is what I'm actually going for as much as possible. OMV Petrol Ofisi is a company that is market leader in the most attractive growth market in Europe. That's the only market which is really growing. There will be a 20% increase in demand in the next five years. That's very attractive. At the same time, we do not have a strong integration.
We just have a limited integration into the other Downstream Oil businesses. That is the reason why it is not in the center of our strategy. That is the reason why we have defined it as a divestment candidate in the situation where we need cash. We have to strengthen our balance sheet as well. Focus areas. That's the same in each of our businesses. HSE first all the time, cash focus, integration, even increase the integration by selective retail and petrochemical investments especially. Of course, even improve performance in operations. That's margin management, operational excellence in terms of asset availability and utilization. That is where we have still a small way, but there's still a certain potential to go. This is something which in Downstream is on the daily routine anyway.
Strict capital and cost management, because we are not accustomed to high margins anyway. Downstream Gas. That's the other side of the coin. That's a totally different business. If you look into the development of gas demand over the next couple of years, what you see is this is demand that is not really growing. Most probably even going down from 2014. Up here because there was a warm winter. If you look at 2015, it's another warm winter. This will be a difficult prediction over time. What we see is approximately 455 billion cubic meters that are demanded in the EU 28. If you look at the supply side, what we show here, the contracted volume in long-term contract. Even that volume is close to the demand.
This means that there will be not a problem to actually supply the demand development in terms of natural gas in Europe. This has several reasons. I do not want even to go to them. They are very cumbersome. Coal, renewables, I think you know the story. If you see on the supply side, here you see this is something which is very important, the indigenous inclusive Norway production decline. The European production of gas will go down very dramatically over time. This is Russia. Clearly, there is a huge supply upside because there is a lot of gas still available. There is a part which is difficult to predict, that's LNG. There is a lot of LNG liquefaction plants currently built and will be built. I'll show you on the next page here.
This will go up, the capacity will go up by 50% until 2020. Mainly Australia, Russia to a certain extent, but U.S. as well. On the Australian LNG is expected to land in China, Japan. Since China and Japan, in the meantime, having natural gas supply contracts, LNG contracts based on the crude price, the price is so low that a diversion from Europe to Asia, which is the usual way the LNG is flowing, doesn't work anymore. This means that the U.S. part of it will actually come most probably as a certain part to Europe because the U.S. LNG will look for the best price in the markets. There is no long-term contract behind the full volume there, so this is flexible. This is good news if you want for our LNG terminal in Gate.
This may be not so good news for the midterm gas price. We have started restructuring. You always start with certain decisions. The portfolio decisions in Downstream Gas have been made last year. First of all, we have to restructure the gas sales business. Thereby, we have signed last year a sale and purchase agreement for the takeover of 100% of the Austrian company, EconGas. Currently, this is in the phase of the competition clearance. We expect to get that in the second quarter of 2016. When we have the full control of that company, we will consolidate the organization behind. This will then serve as the basis for a lean and efficient sales business that will be actually as well the basis to increase our sales and marketing impact in the Northwest European markets. We have decided to minimize the power exposure.
This has been explained as well. Wind park in Romania is already in the process of being divested. The power plant in Turkey, the divestment is under review, but there is a certain probability to the result of that review. The power plant in Brazi, we will continue because we can integrate the power plant into the value chain of Petrom. What we are doing there is more or less producing gas upstream again. We are selling the gas and or using it for the power production in the plant, whatever is the better fit. We have found a way to utilize that plant so that on the Petrom group level, there is a significant positive cash contribution. That's a business that we can continue, and we will keep that one. We shift the exposure from regulated to non-regulated transport business.
You have heard both of that today as well. Reduce the exposure in regulated Gas Connect Austria by selling up to 49% of it and investing into non-regulated Nord Stream 2. That is a shift which obviously will have a positive impact on our return in the business as well. We have to improve gas infrastructure business. What this means is more or less the utilization of our assets. We have a long-term commitment in the regasification capacities of the Gate terminal in Rotterdam, and we are actually very actively working on getting most of that capacity under utilization, because currently it's cost, and we actually have to avoid that cost, clearly. To continue the integrated storage business in Austria. Storage business is getting more difficult because the summer-winter spread is diminishing, and that is the value of the storage, obviously.
At the same time, this is a business which is integrated into OMV upstream, downstream, and this makes on an integrated level still a lot of sense. The gas sales business will be pivotal to the market to market OMV's increasing supply portfolio. We have two regions, two core regions defined. That one is Northwest Europe. We will actually grow the sales position before the background of a growing supply position. Upstream has to deliver there as well. In Norway, the gas production will come to the European markets, and we have to actually actively market the gas. We will launch a sales offensive in Germany that has been mentioned as well. This goes up to 10% of the market in Germany, but only the long term. This is something which we will not be in a position to deliver in one or two years.
This will go over more 10 years than one year. We have the two home markets as well. Again, Austria and Romania, where we clearly would like to keep the market leader position and we will retain the market share that we have in those markets. Before the background of this increased sales business, you see here the Gate terminal, and the logic is that before this buildup of the sales, we will be in a position to have then a higher utilization here and get the cost that we currently have not covered under control. Nord Stream 2, just a few words because it has been mentioned as well. This is a very attractive return, non-regulated return. OMV has a 10% share. The total project investment will be approximately EUR 10 billion inclusive of financing cost.
FID, we do expect the FID to happen in the second half of 2016, startup of construction 2018, and taking it into operation by the end of 2019. This pipeline has insofar a pretty high importance for us because it will be the backbone in securing the gas flow to Baumgarten in Austria, and at the same time, it will have a positive impact on Gas Connect Austria because the gas will then go through that pipeline. This is the planned route to Baumgarten. HSSE, as in Downstream Oil, two key directions, restructure the gas sales business, minimize power exposure, reduce the exposure in the regulated transport business, and increase the utilization of our infrastructure, of our storages, and position for the future in two ways. This is developing an efficient sales business in the Northwest European market and investing into the non-regulated Nord Stream 2 project.
This is more or less the same. That's in a nutshell what we will be doing for the next couple of years in the Downstream division of OMV. Thank you very much.
All right. Ladies and gentlemen, let me wrap up by asking the question, how does OMV look like in the year 2020? It's written as a headline here on the chart. OMV is going to be an integrated company with a sustainable resource base with improved profitability. Profitability was a headline in all the speeches my colleagues and I gave to you. Profitability means, as has been summarized in one sentence, cash is king. It means that we would like to pay the dividend with our operative cash flow, that we are going to increase our production from current 300,000 barrels per day to 360,000 barrels per day. As I'm an optimist, I would say, as we speak about Russia, it's in our hands. It's in our hands, and we will do everything with our management capacity that this opportunity will end up as a positive upside in our books.
Libya and Yemen, just to be precise, it's not in our hands. I only can pray for freedom in two countries. That's all I can do. It's an upside. Our oil is not disappearing because there is a civil war at the surface. There is a potential. We are going to follow a reserve replacement rate of 100% in Upstream. That's the headline of sustainability. We don't produce to the disadvantage of our reserve base in the future. We do have a solution presented to you with a headline and the huge potential to participate with a 24.98% stake in Achimov 4 and 5. In Downstream Gas, as my colleague Manfred explained to you, the market has changed, and we have to adapt the business model. The business model means we were striving for growth. We will Europeanize the business.
We will sell more gas, we will be in a position to cover the cost we do have on our back as we have booked the infrastructure capacities. We are going to sell a 49% stake in a regulated business, keeping financial control by OMV with a 51%. We are going to participate in a very, very interesting, economically highly attractive project, Nord Stream 2. It has a strategic component. Of course, in Downstream Oil, we will keep the business as a very strong cash contributor. We can count on Downstream Gas also in the year 2016. We are going to change. We exit our strategy around Turkey. It's not an integrated strategy anymore. It doesn't fit. Therefore, I think especially in times where in the M&A market, there is a good high premium price on Downstream assets.
We have done the right decision, anti-cyclical behavior in the M&A markets. The divestments we have shown to you are purely in the Downstream sector. Our dividend policy hasn't changed. We will continue to grow the dividend in line with earnings, we will have and strive for a 30% payout ratio of the net income.
Thank you very much. That's a summary of our strategy. Now we are looking forward for the second round of questions. Felix.
Thank you, gentlemen. We now have plenty of time for a second round of Q&A. Please, let's do it like in the first session, please wait for the micro and then pose your questions. Please, Hamish, do you want to start?
Thanks. I'll hit you with both division questions, just starting upstream. One of the things I noticed you skipped over quite quickly was the Barents Sea. I know so far the discoveries in the Barents have been quite small, some of your competitors are quite excited, particularly about the South Barents. Can you tell us how you might be able to build on that? Can you talk to us a little bit through the CapEx evolution with EUR 2.4 billion kind of set between now and 2020? It feels like as you bring projects on, as David explained earlier to me, you're going to be switching that CapEx over into investing in Achimov. Could you tell us how sustainable that EUR 2.4 is? How much do you think Achimov is going to cost? It would be good to know what the sort of CapEx projection of that.
Some of the consultants are suggesting it'd be EUR 1.5 billion. What are your cost estimates? Staying on Achimov, can you tell us more about your due diligence? You didn't tell us a huge amount about Achimov from an upstream perspective. Rainer Seele mentioned you're doing this due diligence. Can you tell us about the reservoir, its characteristics, permeability, flow rates? Whatever you're seeing on that would be good to know. I can only go on what consultants use. If it's all right, I'll just get all the questions out, these ones are in the Downstream. Can you tell us how much of the margin in 2015 was contributed from low water levels in the Rhine, giving you an effective, stronger position? As that changes, will there be an effect?
Can you tell us if you're going to use gas in your refineries to process your crudes? The midterm outlook you mentioned for Europe doesn't include imports. Could you maybe tell us a little bit on the effect of imports on the midterm outlook?
I'd like to take the first questions. The first one is regarding Barents Sea. As we have been announcing already, the volumes, what we are estimating from the discovery so far is 244 million BOE, our share. Currently, we are drilling the next Wisting well, which is a horizontal well. We want to prove the concept that we can exploit the reservoir via horizontal wells. As I can tell you right now, we have managed already the most critical situation, which is the getting into the horizontal section. We are already there. We are in the reservoir. The plan is that we drill and finish this well within 90 days. We are on track with the well. This is ongoing. Telling you more about what will be final recovery reserves, it's too early to give you more details on that.
It will not be less than EUR 240. That's what we know already right now. What are we going to do with the money which we save on the one hand via being more strict on our CapEx spendings and our E&A spendings? I can tell you we have a lot of ideas already right now where we would spend in the upcoming future, those money which once the oil price is ramping up, could be either in additional projects in Russia or in projects Iran or UAE. What I've told you, this is just the beginning. What we are doing right now, we are getting data from those fields where we are in right now. This would need two to three years, and then it comes to a decision whether we will invest there, yes or no. There's sufficient room for additional projects.
There are ideas enough what we have in our pipeline. Regarding Achimov due diligence, this is right now ongoing. Technicians, geologists, they are on site. They're looking into the datas, checking everything. It's too early. I can't give you an estimate on production rates and recoverable reserves and so on. We will know this after the technical due diligence, which is right now still ongoing.
On your Downstream questions, you're right. There was last year, couple of months a low water level on the Rhine, which obviously that doesn't have an impact on the refining margins that we're calculating because the refining margins are calculated on the product quotations in Northwest Europe, in Rotterdam. What this means is that the local price level is going up, obviously, because the supply-demand picture is changing. However, I would think if you just convert it now into refining margin, this would be not very much over the year. That's a minor impact on that. We have benefited and the industry has benefited from that in the fourth quarter mainly, but over the year, the impact was limited. The second question was whether we use the gas in our refineries. Of course, we do that, for sure.
We have even gone to gas turbines instead of sometimes oil turbines in the past. The function is as well, that clearly the gas price is nowadays pretty low, so that's the better source of energy, even for refineries. The third question is a very valid one. There will be import capacities that are coming on stream over time. I think this will be three. One will be the U.S., in terms of diesel, because as I said, the gasoline demand in the U.S. is going up currently, and the U.S. market is a gasoline market. This means the refineries will try to cover the demand for gasoline there. Diesel will be produced as a surplus product and most probably will find a way to Northwest Europe. The Russian refineries are currently undergoing investment programs to improve the specifications, so that's diesel as well.
There will be more diesel coming to Europe out of the CIS. The third point is the Middle Eastern refineries that have been built and are still under construction, will bring additional marginal production of diesel to the Mediterranean market, and as well, maybe even close to the Black Sea. We see those products already there. This will be the third source where the increase is coming. However, as a European point, Europe is short in diesel. This is something where they find a home, but it will not be, in my opinion, having a significant impact on the attractiveness of producing diesel.
I would like to give you a short answer on the investment need for Achimov 4/5. I try to make the math with you together, okay? As an orientation, because the information is already there. Let's assume we're going to have a EUR 2.4 billion investment 2016. Let's expect we are going to keep to invest on that level for the next five years. It's five times 2.4, which is EUR 12 billion in that period. We have set that 5%-10% out of these EUR 12 billion is the order of magnitude we need for the investments in Russia, including Nord Stream 2. Nord Stream 2, I have made the math already. The equity share is something EUR 300 million. I think now you are able to get an idea what is the size of the investment.
Christophe, please.
Yes. I will ask first a question on the upstream. Then two questions on the downstream. Regarding the upstream, in the years to come, you are going to have a decline in production from Romania and Austria, which are, let's say, quite profitable, and replace it with Norway and Russia. Just in terms of profitability, do you think that your Norwegian and Russian production is as profitable as Austria and Romania, considering, let's say, similar hydrocarbon prices? Then, two other questions regarding the downstream. Petchem. Integrated petchem EBIT, meaning excluding Borealis, did quite well this year, thanks to relatively strong ethylene propylene margins. How do you see the margins evolution in the years to come, 2016 and maybe 2017? Should we consider that it will go down in the same magnitude than refining margins?
Given that we are talking about different economics, it should remain relatively strong? Regarding Borealis, can you just remind us the dividend that you received this year from Borealis, and should we consider this will increase given Borouge is a kind of cash machine now? Thank you.
I would like to answer the first one. First, I need to say, we don't need Norway and Russia to compensate for the decline of Romania and Austria. Norway is enough, we'll increase the production in Norway up to 70,000-80,000 BOE until 2020, and it is by far more than the decline will be assumed for Romania and Austria. Regarding profitability. In terms of, give you an example, net operating profit after tax. The best asset we have in our portfolio is by far Austria, and the second best is Romania. Why? Because also we have a favorable tax regime in both countries. To beat this in Norway would be very difficult. Norway is, I would say, has one big advantage. As long as you are investing, you get 78% of the money back, Norway is delivering a stable cash flow right now.
I think this answer, so that Norway bids in NOPAT, where BOE from Austria and Romania would be very difficult. Russia, from my point of view, plays in a different league in terms of cost and in terms of returns. It depends on the result, but we are negotiating at the end in the contract. I don't want to speculate right now what will be or in which range, but what we can ensure you, we will sign the Russian deal only once it's profitable for our business. We'll not sign an unprofitable deal, so to say.
Thomas.
Petrochemical margins are not easier to predict than the crude price, I have to tell you. Obviously 2015 was a peak year for petrochemical margins. Coming already to Borouge as well, Borealis did not only make a high profit out of Borouge last year, but as well a lot of the European business because of the peak margins. One of the reasons for the high margins last year in Europe has been production problems at different sites. Some of the production of the ethylene production went out for a month, the majority of the year. They are back now, this automatically means that the margins will be lower. Since the demand is not bad, I believe the margins will stay strong, yet below last year's level, of course.
On the dividend, this is the same as we have discussed for OMV. The executive board of Borealis will propose the dividend, obviously this has to be approved in the supervisory board. We do have a certain preference to see a higher dividend this year, given the fact that last year was a record year for Borealis.
Can you manage the last year?
Last year, I think the amount was a little bit in excess of EUR 100 million.
Thomas.
Thomas from Credit Suisse. I'll try to do a better job and just ask four questions. First one on Petrol Ofisi. Can you just remind me on 100% basis, how much EBITDA you generated in 2010 and how much EBITDA it was in 2015? Second question on upstream. You used to have a target to produce-
EBITDA.
400,000 barrels per day, including Yemen and Libya. Yemen and Libya contributes 40,000. If I exclude Achimov, when you look at your target in 2020, now it's about 340, including Libya and Yemen. Where is that 60 delta coming from versus the old target? Achimov, can you perhaps say what the plateau potential is? You talk about 20 to 30 years of plateau production. I'm trying to get a better understanding for what will happen to portfolio decline rate. Portfolio decline rate, BP has a 4% portfolio decline rate, Total is 3%-4%.
Sorry, I haven't got the question, the third one. The third one to upstream, right?
Achimov, what's the plateau potential?
Yeah. That's what I got. Yeah.
What does it do to OMV's portfolio decline rate?
Okay.
Portfolio decline rate, take BP, it's 4%, take Total, it's 3%-4%, take Eni, it's 5%. You add long live production, it should reduce the portfolio decline rate. Last one, plan B. If Achimov doesn't happen, how do you replace reserves? Thank you.
Okay. Coming to the first one. Indeed, we had a target, a very ambitious target of 400,000 BOE in 2016 already, and then we aimed to ramp up the production even up to 500,000 until 2020. From my point of view, this target was too ambitious, especially in the last year. We had to stop a number of field redevelopments worldwide. It's not only, but mainly in Romania, which will not come on stream in the upcoming years, mainly due to the low oil price in environment. Main reason was it was too ambitious from my point of view. Achimov plateau production, what we are estimating is between 60,000 and 80,000 BOE per day. That's what you can expect as a plateau production over the next 20 up to 30 years. Because the field life, what we are estimating is beyond 2060. Regarding plan B.
First of all, we don't need a plan B. We will implement plan A. Second one, if worse comes to worst, that we will not achieve an agreement regarding Achimov. I think I presented already some potential projects which we see in Iran and in UAE, which will just take a little bit longer maybe than the engagement in Russia. Because Russia will come quite early on stream.
UAE will take a little bit longer because we just need to finalize the studies, but the potential is big as well there. First of all, we don't need a plan B. If worse comes to worst, we have a plan B.
For Petrol Ofisi, I do not have the exact numbers with me. I just memorized that in 2015 the EBITDA would be in excess of EUR 200 million. We will, however, confirm that number, and as far as 2010 is concerned, we will let you have that number, because this is not in our minds and not in our books anymore. Most probably it was higher.
We simply don't have it in our minds. The number exists, clearly it exists, we have a limited mental capacity and unfortunately that fell off. We will provide that information to you. It was clearly high because during the period between then and now, we've obviously had a substantial degree of regulation of the margins. Margins come under pressure since then, we will provide it to you.
Good.
I can support you with the number. It was EUR 214, 2015, and have it back to 2012, we had EUR 300, but 2010, I can provide to you later, yeah?
Si.
Please to the back.
Waiting for EUR 1,200.
Yeah. Hi, it's Marc Kofler from Jefferies. I just had a question on the downstream, and then I wanted to come back to the dividend, if possible. Just on the downstream, I was wondering what, in the context of the overall group, free cash flow, you referred to mid-cycle margins. I was just wondering if you could elaborate a bit more on that, and perhaps in the context of where we are today. Secondly, on downstream, I noticed in the press release you talked about some planned maintenance, which is quite heavy, for 2016. Is that the big delta versus group throughput for 2015? Or are there plans to lower utilization rates given the perhaps softening in the margin environment? Shifting on over to the dividend more generally. I've noticed you talked about growing in line with earnings and the payout ratio.
It strikes me that earnings growth this year, up in 2016, could be quite difficult. I was wondering how to think about the dividend in that context as well, please. Thanks.
I start with Downstream.
What was Downstream?
On the free cash flow in mid-cycle. Without having now very accurate definitions, what is the mid-cycle and so on and so forth. What I can tell you is that in Downstream, what we are doing is we are investing sustainably under depreciation, first of all. We have an investment level, which is approximately EUR 500 million-EUR 550 million per year. If you see that the depreciation is EUR 600 approximately, then I would guess under mid-term average refining and petrochemical margin environment, we will be in approximately EUR 500 million per year. Last year, we had a free cash flow in Downstream of slightly in excess of EUR 850 million. As far as the maintenance is concerned in 2016. In 2015, we did not have any turnaround in none of our three refineries.
Next year, we will have a turnaround in the Schwechat refinery. We will have a turnaround in the Romanian refinery, Petrobrazi, which obviously will have an impact on the capacity utilization. What we do and what the industry is usually doing is that you increase your inventory before you go into turnaround. You use the spare capacity that otherwise would be available in order to prepare to build up the products to be sold during the turnaround. Capacity utilization will be going down, doesn't mean that the sales will have an impact.
On the dividend, the payout ratio of 30% has been a long-standing group target. Clearly it's very seldom that you hit a point landing, as it were, in terms of the 30%. There have been times when we've been above. The current payout ratio is 36% based on the clean net income. There clearly been times where we've been below. I wouldn't read too much into current prices and that payout target ratio. Genuinely though, as regards to dividend for the current year, it's far too early to talk about that. I think our message has been fairly consistent about the dividend we've just declared. We wait until the year's gone. We look forward going into the years beyond that, before we make any concrete statement about what the dividend would be. I wouldn't read too much into it at this point, frankly.
Great. Michael, please.
Thanks. Michael from Citi. I just got a couple of questions, one on the Upstream, if I could. Just around the deeper potential in Romania in terms of the onshore. I'd appreciate just to get an indication really on the potential resource that's there. Also costs are coming down. I just wonder what the break-even potential could be of developing that resource in the current environment. Then just secondly, on Petrol Ofisi, just wanted to get a sense as what the book value currently is in the accounts for that asset. Thank you.
First one regarding deep potential, as I mentioned and talked about it, there is still big potential because there were not many wells drilled deeper than 3,000 and 4,000 meters, just a few. Regarding breakeven, I can't tell you because it depends really on the projects, and it depends on the volumes. What I can tell you is the breakeven from an average from the development projects which we have performed so far in Romania, we had a breakeven between $12 and $15 per BOE for the development projects onshore. I would expect that this is in the same range because the volumes usually, as we have seen into there, are higher. They need shallower reservoirs. Therefore, I think there's a good chance to be in the same range than what we have been experienced so far.
The book value of Petrol Ofisi was approximately EUR 1.6 billion, in our ac counts.
Okay. Haythem?
Thank you. Haythem El-Rashidi from Morgan Stanley. A couple of questions from my side, please. If I could come back to the upstream. Just an observation or a question, just the new projects you've got coming on stream, or even the asset swap with Russia, Achimov, Nawara, Aasta Hansteen, this is all gas, and it seems there's this increasing move towards gas. I just wonder if that just happens to be the projects you have, or is there an intentional strategic move towards a more gassy portfolio? Second question, just actually clarification on the turnarounds with Petrobrazi in Schiehallion. Just could you give us a sense of timing, how long they would be out for, and over which quarters? That would just be helpful. Then a final question, and I appreciate that you've outlined already a number of measures you're taking to respond to the weak oil price.
Given the nature of these markets and how quickly they are moving, say we roll forward another six to eight, nine months and the oil price hasn't really recovered from where it is at the moment, and given the assumptions you're going with at the moment of EUR 40 and EUR 55. You've talked about CapEx not really having a lot more flexibility. What's the other flexibility you have here? Could you issue more hybrid debt? Are there other things that you would be prepared to do? Would you accelerate asset disposals other than the ones you mentioned? Just a sense of what else you could do, that would be very helpful. Thanks.
I would like to answer the first question regarding whether we are more oily or more gassy as a company, let's say in this way. Right now we are producing roughly 50/50% oil, 50% gas. From the future projects, there is also an oil project. Schiehallion is clearly an oil project. So if Achimov or excluding Achimov, we would stay around 50/50 for oil and gas until 2020. If Achimov will come on stream and once we reach plateau production in Achimov, we would produce more gas than oil. But this is not a real strategic intention. This is rather depending on the opportunities where we get the highest profitability, whether this is in oil or in gas. There's not something where we say, "Okay, we focus only on oil projects, or we focus only on gas projects." Yeah.
I think it's also having a portfolio which have this 50/50, I think is a good strategy, which we have, and we want to keep it, and it will stay there. Yeah. It might change a little bit towards 45/55 or something like that, but we'll not move far away from this 50/50 with the upcoming projects and which we have in our pipeline.
The average length of the turnaround is approximately five weeks. Each.
I would go for the flexibility. If we have that, let's say worst-case scenario you are predicting here, we really have to see how our partners also react. We are not alone in our industry. We are not alone in the projects. Especially our projects in the North Sea are not coming with the operatorship of OMV. We have to check how our partners are going to react in such a scenario. Then we will check whether or not committed CapEx is really committed also from our partners. That would be one first point I am going to test. The second is, of course, we are going to focus and intensify our intentions then to further reduce our manageable costs. The third aspect you have mentioned is asset disposals. If we go for further asset disposals, I don't want to speculate on this.
Asset disposals, if you start such a process, it will not really kick in in a very short period of time. You need a longer-lasting process. Just take Petrol Ofisi. We just decided today. If I want to decide something today, it will not really save 2016 in terms of cash.
Thank you. Oleg, please.
I will take a lot of microphone.
Hang on. Micro is coming. It's there.
Thank you. Oleg Galbur from Raiffeisen. I have two questions. The first one on Petrol Ofisi. At the end of 2014, looking at the latest available balance sheet on the company, we see a net debt of $1.3 billion and a net working capital of some $900 million. I was wondering if you could share with us how does these two indicators stand at the end of 2015, or at least mid of 2015? The second question is on upstream. Would you be so kind and provide an update on Rosebank?
How should we look at this project? Should we rather consider it as a sunk cost or as still trying to re-engineer the whole project in order to lower costs, et cetera? Thank you.
On the financial position of Petrol Ofisi, we can take some time with you and show you how we get to the EUR 1.6 billion. What you refer to as Petrol Ofisi's disclosed net debt was to OMV. It was funded through intercompany funding. The EUR 1.6 billion that Manfred mentioned a second ago is OMV Group's net book value exposure to Petrol Ofisi. That's the overall position. How we get to that in terms of the various elements of the balance sheet, Felix could take you through at a subsequent point. The net debt that you're talking about is effectively within the EUR 1.6 billion because the net debt that they had was to OMV, so it was a consolidated position.
Regarding Rosebank, as you know, Rosebank was part of the Statoil deal where we increased our share up to 50%. What we also did right from the beginning, we announced that we will farm down our shares. That's what's going on right now. I can't tell you more about details about it because it's an ongoing process. Regarding FID, we have delayed FID because we'll not take FID at an oil price environment of $30 per BOE, where breakeven is very much above the $30 per BOE. I can't tell you more right now. If the oil price is going up, we are working on it. We are working right now on bringing the CapEx down, and we have already achieved a lot. We came down from EUR 12 billion down to EUR 8 billion.
We will not take FID as long we cannot prove commerciality on this project.
Hi, it's Josh Stone here from Barclays. You gave a fairly cautious outlook on refining margins in Europe, yet also acknowledged the oversupply in the crude markets. To what extent were you able to optimize your crude slate in 2015? Do you see further opportunity, perhaps processing heavier crudes or more discounted crudes in 2016 to enhance your margin? Thanks.
Thank you for the question. What we have been doing is to even intensifying the optimization of our crude slate because there are more crudes that are currently offered on the market with having a higher value in terms of refining processing. For instance, just to give you a few examples, what we have done is we have imported from South America or Mexico. These are crudes that if you get a certain cargo, could create a significant additional value. We have at the same time, by the way, last year, for instance, bought 23 cargoes of Libyan crude. Libya is obviously not producing in terms of the foreign companies, but NOC is producing to a certain extent. It's not reliable, but we have actually got hold of 23 cargoes, which was obviously very beneficial for us.
To put that in relation to a refining margin, that's pretty difficult. It is creating a few hundred thousand EUR per cargo if you are successful, and if you take 20 or 25 or 30 per year, then this obviously has a positive impact. Iranian crude will be available nowadays again. This is something where we are looking into. We are bringing crude from the Middle East and the Far East as well. The Kurdish region is offering crude. There is a lot of crude available, and we are very flexible in our refineries, especially in the Schwechat Refinery. We are running approximately something like 25 different crudes per year. There is a big flexibility there. Not so much in Burghausen, I have to say, because that's 100% integrated into petrochemicals.
This is not such a variety, we are stretching the options there as well, for sure.
Matt?
Thanks. Matthew Lofting at Nomura. One question each on upstream and downstream, if I could. On the upstream side, I guess looking at the picture you showed earlier of the three core regions, New Zealand seems to conspicuously sit outside of all three of them. How do you see that medium-term? Is it really viable within the portfolio you have, or is that effectively a disposal candidate as and when upstream macro conditions improve? Secondly, on the downstream side, there's clearly on gas, specifically, a number of restructuring decisions that have been taken, arguably at this point, not too many specific timelines against them. I think, Rainer, you talked earlier about wanting all of the divisions to be profitable on a standalone basis. When do you think you can conceivably deliver that on the gas and power portfolio broadly under current market conditions? Thanks.
I would like to answer first the question regarding New Zealand. New Zealand is clearly not a disposal candidate, New Zealand is also not a core region. I would say why, because as we defined for our core regions, we want to ramp up production up to 50,000 BOE. New Zealand, we will keep. New Zealand is highly profitable, even in the low oil price environment, which we see right now. It's one of our positive contributor to our EBIT.
We'll not invest further and will not grow New Zealand up to 50,000 BOE per day because, let's say, the barrels or the cubic meters are not there. We don't see this potential. We don't declare New Zealand as a core area to bring it up to 50,000 BOE per day, because it's simply not possible. On your questions to Downstream Gas, the sales business clearly should be very soon positive. This is within the next two years, I would guess. We have to be positive there. This will come after the takeover of the, as I mentioned, the 100% shares in EconGas. The power business is not unprofitable. Coming from the other end, in Romania, we have a problem in Turkey. As I mentioned, we do not lose cash there, it's not something which is a disaster.
This will take time because the spark spreads in Turkey are very much under pressure, and I do not see a significant recovery over time, to be honest. As I said, this is the reason as well why we are currently evaluating a divestment of that asset anyway. In terms of the transportation business, this is highly profitable. In GCA, if you see the return, that is a limited return, but still even nowadays a pretty attractive return, I have to say, and a very stable business. In Nord Stream 2, we have given you the cycle where actually the pipeline will go into operation will be in the beginning of 2019. This will come then together with the revenue out of the gas transportation agreement.
Thank you. Do we have any further questions? Yes, please.
Hi, it's Mehmet Dari from UniCredit. I have just two small questions about your credit rating. As the whole sector is placed on credit watch, what would be the financial impact on your company if you get downgraded by one notch from Moody's? Another question, what about your refinancing needs for 2016 and 2017? Thank you.
We have approximately EUR 1.4 billion of cash at the end of the year, following the issue of the hybrid bond in quarter four. What maturities there are in the next two years are substantially below that level, around about half of that level. In terms of immediate refinancing risks or challenges, they are non-present. Our average debt maturity is about five years. In terms of the overall maturity profile, it's relatively robust. On that basis, therefore, clearly, a theoretical downgrade by the rating agencies would have no immediate impact, given the absence of any immediate refinancing needs. Clearly, in the future, it would not be helpful. Would likely to lead to some increase in cost of that refinancing.
James, please.
Sorry, just one very short question. This is really for Manfred. Have you been offered any Iranian barrels yet? If you have, how do they compare in price to the Russians?
I have to give you a bit more of a background. Would be already useful to go for Iranian barrels. We're in discussion with NIOC. We had a power shortcut in Austria in the vicinity of our Schwechat refinery. This has caused us certain production problems where the inventory is now not at the mix that we would like to see, and that's the reason why we're currently not going for Iranian crude, because we have to work out the crude that is actually already stored there. However, I cannot give you a difference in terms of prices because this is always depending on the quality and on the products that you can get out of it, Iranian crude is offered at a pretty attractive price currently. Yes.
How much?
Sufficiently. The discount is sufficiently high that there is already significant streams coming to Europe.
Thank you. Do we have any further questions?
Can you get the microphone?
Yeah. Okay.
We have a question from Robert Stevens. Could you please provide some additional information on the Black Sea drilling results and how many of the seven wells discovered gas? What resource additions do you estimate you achieved from the campaign? Also from Axel Frank. Besides the low oil price, the volatility of oil prices remains a big issue for oil corps because of their long-term investment horizons. There are several drivers which contribute to decarbonization needs of OMV supply chain Downstream in the midterm. The question is: How does OMV respond to these overarching trends beyond incremental actions presented today?
I'm going to answer the first one regarding the Black Sea. As I said already, we have been drilling seven wells in the drilling campaign 2014-2015, which we finalized beginning of 2016. In the majority of the wells, which we have been drilled, we discovered hydrocarbons. As I said, it's too early to give you a final figure on additional reserves, on additional resources, because now, what we are doing is we are collecting all those data from those wells which have been drilled. I think we will be at the mid-end of the year, we will be in the position to give more detailed information, what is the estimate regarding recoverable resources. What I said, we stay committed to the range, which we said in 2012, between 1.5 and 3 TCF.
All right. I take the question on decarbonization. Well, honestly speaking, the word decarbonization is not top-ranked in my vocabulary. Might not be a surprise, but I don't see it in the framework of our strategy. I got to make reference to the International Energy Agency. If you look mid- and long-term, if you look what are the primary energy sources, you will find out that 70%-75% of the primary energy is backed by fossil fuels. No way out. I don't see a picture that we can substitute fossil fuels and decarbonize our energy world from one decade to another decade. I think we are going to be still in a good business in 2040, and I think that OMV also will produce oil and gas in 2050.
Talking about the ecological shift in fossil fuels, I think there is a huge potential if we are going to substitute coal. If we are going to substitute coal fire plants in Europe, just to mention a potential to reduce CO2 emissions over here in Europe. It was calculated that we can reduce 15%, enormously. What I'm going to tell you is we can't make it just purely in a short term and mid-term with windmills and solar panels. If we really would strive for, especially in Germany, you can see that this can have just impact by reducing CO2 emissions. I think we need to have a shift in fossil fuels. That's what I'm going to see short and mid-term. It will be in favor of gas.
Thank you. Do we have further questions in the room? Master, please.
Yes.
Yes.
Adrien Abatis, Société Générale. Regarding the discoveries that you've made with ExxonMobil on the Black Sea, just wanted to know, what do you want to do with this natural gas? Do you think you could have a good profitability by selling it locally? Do you need to build a gas pipeline to bring it to Europe in order to find some customers for this gas?
All of it. The point is that we will sell locally, yes, in case there is a successful development and an economic development. The FID taken, we will sell a lot of the gas into the local market. We will not have to build a new European pipeline because there are interconnectors already. What we have been looking into is, this would be feasible, to bring them into a status in terms of capacity to bring the gas to different markets in Europe as well. You do not need a Nabucco or something like that if you are referring to this one.
Thank you. Any further question here? Great.
No, no problem.
If that's it, thank you, gentlemen. Thank you for everybody in the room for being here and for participating that actively. As usual, the Investor Relations Department is always at your disposal if you have further questions. This event here will be available as a replay on the internet. Thanks again. This concludes the conference. Have a safe day.