Good morning, welcome to our Investor Days in New York. Today, we're going to talk about the future, we like to start from the past, the past 2 years. We talk about the past because we want to understand where we are now, on what we are going to build our future. Less than 3 years ago, really before the big oil drop, during a European gas crisis, also mid and downstream crisis, we presented to our investor community our objectives, also our transformation and the restructuring program of our company. Now that we are at the end of this first phase of transformation and restructuring, we'd like to present what we have done, our achievement, especially how we cope with this period of very big transformation in the energy sector.
We can say that we presented our transformation and our restructuring program before the oil drop. That was very positive for us because we had time to be ready. The reason why we wanted to change the business model of our company was really to be more effective and more focused on our upstream business. Suddenly, we had the oil drop by the end of 2014. We were in the position to accelerate our action of transformation and restructuring of the company. We can go ahead with the first slide. Go ahead. As you can see, when we started our action, it was really because of the EU gas demand and the refining margin, and the refining situation.
You see that in few years, we lost in Europe more than 100 BCM of gas in thermal consumptions, also the price went down, also has been a big shift in the hub volumes. The hub volume passed from 25% to 75% in the European gas market. Why this is important? The gas price, the hub price, is not oil linked. In all our long-term contract, for more than about 40 billion cubic meter are oil linked. That had a very bad impact on our long-term contract and our gas situation. We add the refinery margin, the refinery margin is not just the only problem because we passed from more than $7 per barrel to less than $3, we lost also about 10% of the consumption. We add the oil price.
This scenario was particularly critical for European region and for worldwide, the oil price. We had 2 choices. The first choice is to cut investment, reduce activity, and lose value in our asset base. The other choice is to start, we are already started, a strong transformation program and change the business model of our company. Now we are going to present an infographics that practically describe all the milestones, the achievement, and the activity that we did in the last less than 3 years, really to change our company. We are going to understand where we are and what is Eni today, because it's completely different company respect to 3 years ago. Now if we can go with the infographic, and go through all the main steps, please. That is what we have done.
Our transformation or our process was based on three main pillars. The first one was the transformation of the company that was practically a refocusing and streamlining of our organization and of our structure. The second point was the restructuring of the midstream business, the gas business and the refining business. The third point was to enhance our upstream model, to be more effective, to be able to cope with the low price. Instead of cut investment, be able to continue growing, optimizing our cost, and that's what happened. The first point is the restructuring. That is a very schematic picture of our company, what it was in 2014, what it is today in 2016. What we have done, we passed from a divisional organization. That means that we have duplication, with duplication in the business, duplication also in the function.
We pass from a divisional organization to a more streamlined and business-oriented. Now we have really all the business that report directly to the CEO. This action, reducing the duplication and streamlining the organization, allow us to reduce on annual basis, in a structural way, about EUR 700 million per year. Now we have a reduction of more than about EUR 700 million per year, and that is the main result. That is what we have done for the organization. We had also a deep restructuring in our business model. Eni before was more similar to a conglomerate because we had different kind of activities. We have the Snam Rete Gas that was in charge for transportation, storage, regasification. We have Saipem that was in charge for engineering and construction. We had Galp. We had other participation. We change drastically this model.
We dispose in 2015 of Snam Rete Gas, we dispose of Galp, and we, in 2016, we deconsolidate Saipem debt. That means for us, this transformation of our business model meant for us about EUR 10 billion that we are able to cash in. Next slide, please. After the restructuring of our organization, also of our business model, we go through the restructuring of the mid-downstream. The mid-downstream had, as I told you before, a problem in term of quantity of gas, volume of gas, price of gas, and also the fact that our long-term contract was linked to oil price, and the hub are not linked to the oil price. We had to start a deep phase of renegotiation of our gas contract. Not only that, we have also to recover the take or pay that we accumulated starting from 2011.
We have been able, as a first step, to renegotiate this contract with Gazprom, for example, and recover immediately in 2015, EUR 1.6 billion coming from the recovery of the take or pay. We work on the supply chain, and we had an objective to reduce about EUR 350 million of cost in the supply chain, that is mainly the transportation and the storage, and recover already EUR 200 million from the transportation side. This morning we announced a very important result because we finalized the renegotiation of the Sonatrach contract, aligned this contract to our Italian hub, and that is very important result that will allow us to get the breakeven for gas and power as we schedule, and as we promised in 2017.
That is a very important achievement, and I'm very happy that, just today, here in New York, I'm able to announce this big, important agreement. In gas and power, we start this restructuring, and we have been able to go back to a breakeven. In refinery, I think that was another big problem because we, for more than eight years, we got a negative EBIT and also negative cash flow in the refinery. We made a big effort, first of all, to reduce our breakeven because, as you see, in 2008, we had a breakeven of $7 per barrel. With a refining margin of $4, we lost money, and we had to make a big effort to reduce this breakeven from $7.5 to $4.2. That has been made through a restructuring. In terms of capacity, we reduced our capacity by about 30%.
We shut down a plant, we built and we are under construction two plants, two green refineries. We increased the efficiency of our refinery from 65% to 95%. That helped tremendously to reduce our breakeven price. Starting from last year, for the first time in more than eight years, we have been able to reach a positive EBIT and a positive cash. Now the refinery marketing is more than breakeven in terms of EBIT, and they have a positive cash flow, and they are self-financing. The same restructuring has been done in the chemical business. The chemical business has been negative for more than 20 years. We have been positive just for a couple of years in the past.
We made, also in this case, a very important action of restructuring on the efficiency of the plant, that was the first point that we started immediately, but also on the product. We passed from the intermediate product to the specialties. Increase our specialty up to 40% of our product. That means that we are able to reach, we can stay on the value chain up to our customers. You see the result. That was our EBIT in 2013, and that is our EBIT now in 2016. If you look at this sector, the mid and downstream, if we can change, next slide please. If you look at this sector from a cash point of view, you can appreciate the fact that 2015, 2016, a business that has been negative in the last years, now is back to the profit.
We produce a cash of about €5 billion. Overall, if you compare the previous three years and these three years, we have an increase of about EUR 9 billion. That was a very important point to counterbalance the very low price impact. If we go to the next slide, we pass the third pillar. We talk about the transformation in terms of organization and business structure, the restructuring of the business, of the gas and midstream business, and now we talk about the upstream. The upstream, clearly, we had already a very strong upstream, but we had to fight and counterbalance the very low price. We work on the process. We had to be more effective in the delivering of our production. We had to increase our exploration efforts, not just in terms of finding reserves, but in terms of time to market.
Exploration, from our point of view, in our model, is really part of our production. We look at the exploration reserves, like really in relation to the next production. Just to give you a value, in the 3 years, the exploration production, we can say, represents 25% of our growth. What we got in the last 3 years, you see, in terms of production is exceptional, in terms of value as well. We increased our production, starting from 2013, of about 15%. That means more than 250,000 barrels per day on average. We have been able, in a period where we cut our cost of about 30%, reducing our cost of 30%, we have been able to increase our production of more than 15%, 250,000 barrels per day. That is the volume that is important, but we have to look at the value.
If we compare the 2013 and 2016 operating cash flow, we use the same price of 2013, we can normalize, we can compare the two operating cash flow, we have an increase of cash flow of 30%. If you look at the cash per barrel, that is another important parameter, always at the same condition, we have an increase of 20%. Clearly, that is a very important result. It allows us to pass from 1,600,000 barrels per day at what we are producing now, that is 1,850,000 barrels per day. That is an impressive result. That come from the change of our upstream model. In the next part of the presentation, we're going to elaborate on how we have been able to increase so rapidly the production. Now, we still talk about the value.
We saw that we increased production, we increased the value of each barrel. That has been possible because we improved the cost structure of our asset base. If you look at what happened in this period, the average break-even of our project passed from $45 per barrel to $27 per barrel. We reduced our average break-even price of 30%. How that has been possible? First of all, because our asset, our production, our exploration, passed through an organic growth. We start from the exploration. Our exploration cost is lower in the industry. Just to give you a figure, last year, our exploration unit cost was $0.50 per barrel. The average in the last 8 years is $1.20 per barrel. That is between the 15% and 20% of the unit exploration cost average in the industry.
Our technical break-even start from a very low level. We have the development cost that I present about that has a value account for $11 per barrel. We have the operating cost that are now about $6.40 per barrel. We have a technical barrel that is well below $20. If you add royalties and taxes, you arrive at the $27 per barrel average. That is one of the reasons why each barrel got a much higher value than in 2013, and that happened in less than 3 years. If we go ahead, please. We see the cost optimization. That is another important point because not only we increase production, we restructured our businesses, we have been able to reduce all our cost structure. From a group CapEx point of view, we reduced our cost of about 33%.
In the upstream, as I told you, we reduced our OpEx. We already had the lower level OpEx in the industry, but we have been able to reduce our OpEx of about 23%, and the G&A that I presented before with the restructuring of the company of 33%. The overall action produced a saving of EUR 10 billion in the period, so in these three years. That is another important point because we have been able to reduce these costs, reduce the CapEx, OpEx, and G&A, increasing our production. If you look at the next slide, please. We have, I think, the ultimate goal of our action, and the more impressive one. You see that is our cash neutrality in 2013 and in 2016. When we talk about cash neutrality, we talk about the capability to cover through your operating cash flow, your investment.
In 2013, our cash neutrality was of $127 per barrel. It's huge number, but the industry in 2013 reached really the maximum of the inefficiency with a very high cash neutrality. We were not alone with this high value. What happened that we had really to change completely the big transformation we made, through the cost cutting, through the increasing production and reducing the exploration cost, reducing the production cost. We have been able, in less than two years, to reduce more than 60% our cash neutrality. Now our cash neutrality is $50. That means at $50, we are cash neutral. On the other side, you see another very impressive result. If you compare the cumulative operating cash flow in the three years period, what we had in these last three years, 2014, 2016, $64 per barrel.
We got $34 billion of operating cash flow. That is absolutely in line with the operating cash flow that we got in the previous three years, but at a different price, at $110 per barrel. We have been able, with the effort on the cost, because we increased the production, and we increased the value of each barrel to compensate at the end, the oil price. Practically, we more than double the value of each barrel that are oil and gas. Clearly, we are talking about oil and gas. That is, I think, the most remarkable, and that is also the ultimate result, and describe, as I told you before, we'd like to start from the past to understand where we are and who we are. Clearly, we are a different company. All this restructuring and also the transformation in our organization are structural.
These results in term of cash neutrality, in term of OpEx, CapEx, are structural. We have to maintain them, but are part of our organization, of our business structure now. Now, I'd like to elaborate a little bit more on the upstream side that has been at the base of this big result. Talking about the two main legs of this business that are the exploration and the development. If we can start with the exploration. I'd like to talk about our distinctive model, because we have been so successful in the last seven, eight years, and also the reason why we've been successful, I think, is also because of our strategy in the exploration. I think you see the yellow small fish that is going in the different direction. That means that Eni took a different direction.
We have been unconventional because we went back to the basis, and we decide to go toward conventional asset. Conventional asset means for us, asset that are shallow water, onshore, that are in a conventional lithology, that are less risky in term of drilling, in term of costs, give you a less exposures. Typically, our choice was to go back to the mature area. Most of the cases then we are going through, and we're going to present a really mature area, where mature means that the relinquishment of our company, where other company drilled already a lot of wells. That happened in Angola, Congo, in Ghana, in Egypt, in Libya, in Indonesia, so it's not just a single case, and look for a different kind of target. Which kind of target?
For example, we went back to this area, and we try to explore the deep pre-salt target, deep in term of reservoir, not in water depth. We try to, instead to go to look for structural traps, we went to more risky trap, stratigraphic traps, that are most risky in term of closure, in term of finding oil. We started developing proprietary technologies, really to be able to process, to make a deeper process interpretation of the whole seismic. We use whole seismic, we use new technology, and we use also new interpretation models. Zohr came from a new idea that we took from what we discover in Venezuela, in Kazakhstan, and in Libya. We put together, we create a new model, and we discover Zohr, for example.
All the other discovery in West Africa came from a pre-salt that has been neglected or not considered in the past, or gas that has been left behind because maybe 20 years ago was not commercial. Now it is a product that we can sell. We went with a different model. This different model create also our cost base, our cost because we are conventional, because we are close to our facilities, existing facilities, because we are in a mature area, because we are close to our field, existing field, sometimes in the same block, in the same area. Means that we already have a contract, we can recover immediately the cost. We are immediately a positive cash flow because you are in the same license. That create this big advantage. If we go next, and we look at the result.
The result are quite impressive. If you see what happened, starting from 2008, we discover 13 billion barrel of resources, exploration resources. A very huge number. If you consider this 13 billion represent in the period 2.5 what we produce in this period, 250% of what we produce in the period. If you look at the average of the industry, the average is 30%. The other company in the same period, at an average 30%, we had an average 250%. We discovered 250% what we produced. That is quite important for our future. Also that is quite important because gave us a big flexibility. When we think about the cost, when we think about that we have been able to increase our production of 15% and reduce our cost to 30%, why that happened?
That happened because we have so many new resources in very easy situation, conventional situation with very low CapEx, very low OpEx. The time to market is shorter because you can use your facilities or existing facilities that you can increase your production and shift your investment in project that are less costly. You spend less, and you get your production faster. That is the reason. Exploration not only gave us a huge amount of reserves, but it gave us also the flexibility to reduce cost and increase production at a lower price, at a lower cost. If you see in the other part of the slide, we have this reserve that we discover in the last 7 years, and we already gave value to 15% of these reserves. We have 1.5 billion already transformed through an FID in P1 reserves.
We have already the gray part portion, that is 2.5 billion, already disposed. We already anticipate, we already get value from that. We sold, we farm out, clearly with a big, a huge add value. That is so. We can consider that 50% of what we discover, we already extract value in term of disposal or the part that is under disposal. The rest are already 2P and 3P reserves. The characteristic, the kind of reserves allowed us, conventional one, allowed us to be very fast in dispose our reserve, have an FID, and transform the rest already into 3P reserves, 2P and 3P. We are very close also for the red sign to go to an FID in the last couple two, three years at very low cost. I think we have an infographic.
Si, we have an infographic for Zohr. That is an example of this successful exploration effort. We show Zohr as a last example, if we look at the map, we did discover in more than 10 different places, different regions. In the same condition with Zohr. Zohr has been discovered in a big block where in the past other companies already drilled 11 wells. We went back with the same kind of idea I told you before. Zohr is a deeper target, is a carbonate as you saw, that was not really well seen by the previous seismic interpretation. We use the same seismic while we reprocess this seismic with our proprietary technology, we saw something that others didn't see.
Zohr as an example, where we're close to Zohr, we discover in the same period, that was July, August 2015, a few months ago, we discover also Nooros. Nobody talks about Nooros. Nooros has been discovered with Zohr, the same day, the same week. Nooros is already producing 160,000 barrels per day. We discover in August 2015, it's already producing 160,000 barrels per day. Why? How we can do that? That has been a big contributor in the 15% growth rate we had. Nooros is close to our facility, used practically a gas plant that was half empty, the same pipeline. We just had to drill a well and tie in using the pipeline, the flow line, the plant. The time to market was practically zero because after 1, 2, 3 days, we could test the well and tie in and produce.
That is an extreme example, but very significant. Nobody talked about that because Zohr was so big that the poor Nooros has been neglected but is there with a very huge production. In this period we had the possibility, because of Zohr, and before Zohr, to renegotiate our gas contract in Egypt. We increased the gas price. After we increased the gas price, we discover Nooros already in production and Zohr. We have other kind of big discovery. One is Marine XII. Marine XII is oil, it's in Congo. The Marine XII has been a very old block that we got just to have gas for the power plant. We discover Litchendjili that's a field, and Nené that is another field, and overall we discover 6.3 billion barrel of oil in place. That has been done in one year.
After 11 months, Nené was in production. The time to market, 11 months. The same reason. Conventional asset that is pre-salt, so not easy to discover, but if you have the right technology, you can do that. Has been discovered, and after 11 months, that for different reason because we use a standardization, a modernization in our engineering, so the design to cost was really very effective. We put in production the Block 15/06, the same. The Block 15/06 is a relinquishment of the Block 15, that block where we are with Exxon as operator, that we took, and we discovered 3.2 billion barrel of oil. Is a deep offshore, and despite that is deep offshore, from the last well, exploration well, and the production, we got less than four years. Then we are producing constantly, and we already reached 100,000 barrel per day.
Everybody knows Coral because it's very famous. Mozambique is a big gas discovery. That is a greenfield, so is a different kind of situation of the other. Then we have Jangkrik in Indonesia. Merakes, the same kind of stuff. They are relinquishment that other company will discover. In this case, the total discovery is about 7 TCF. It's good because we have facilities there. LNG very close, Bontang close to our facility, so we have just to invest in the upstream. The midstream is already there, so the breakeven price is very low. Then we have other big discovery because we discover in Ecuador exploration again in very old blocks. We discover more than 400 million barrel of oil. We have discovery in Gabon in the same situation, pre-salt.
The same kind of structure of Nené, and we discover about, in this case, 1 billion oil equivalent gas and condensate. There's Sankofa in Ghana. Johan Castberg is not our discovery. We made with Statoil, but it comes from a geological model that is a Goliat geological model. That is really what happened in these few previous years that allow us to reduce our cost, be conventional, and immediately use this exploration to start production. I told you, 25% of this 15% in production growth was coming from this exploration. Next, the development. We talk about the exploration, and then we have the development. That is the second part. What we have done in term of model, we apply the design to cost model that normally we use in the development, also for the exploration. The exploration has been practically linked to the development.
What that means? Means that the selection that we made, when we select our prospects, we select the prospects that allow us not just to be less costly, but that allow us to reach production very fast. For that reason, it's an exploration design to cost. That maybe is quite new because nobody talks this kind of language, because it's really for the development. Our exploration starts, and now I show you, start with the development. We have different cases. What happened? This is a standard way. We have a sequential way. We have the exploration, the reservoir studies, engineering, and then the procurement, and then the first oil. Very, very huge time to market. That is a traditional way to reduce risk, but you are very slow, and there is no iteration and overlapping of the different parts. That is our model.
That is a full design to cost model. When we are exploring, we have a first well, we have the second well, we are already making the reservoir study, we are already making the conceptual engineering model, and we start with the procurement. We overlap the four phases. That is quite unusual. You say, "You take a risk when you make these four phases together." No, you are not taking risk. You are gaining timing. You make a shorter your time to market. What is happening that there is an iteration? Every time I have a well, I run my reservoir model, I update my conceptual engineering model, I also update my FEED, so the front engineering, and then I start with the procurement. Zohr is a typical example. We see, we did the Habanoos, we made the same thing. Nené, we made the same thing.
Sankofa, we made the same thing. The Block 15/06, Jangkrik. We applied this new model in the last three, four years. For that reason, we have been able to have very good time to market, and we could increase production in two years. What happened, for example, it's very peculiar because you know that this year we had an issue in Val d'Agri. Val d'Agri is an Italian field. Maybe you don't know this field. It's a good producer, about 80,000 barrels per day of oil and other 10,000 of gas. For environmental reasons, we solved the problem, we had this field stuck for, closed for five months. We lost it. With this field and with Nigeria, about 55,000 barrels per day. We have been able, through our exploration effort, to compensate. Respect our budget, compensate 55,000 barrels per day in 2016.
That because we use this different kind of model. I'll give you an example immediately with the Zohr again, if I remember well. We have Zohr, yeah. That's an example that we can replicate for other project. We discovered Zohr in August 2015. We drilled the first well, successful. In September, we already made up the plan of development. In October, with one well, we went to the authority, we got the approval for the plan of development. We start the procurement. We start the second well, and once we got the result of the second well, was January, we test it. We saw the production was exceptional because the production was about 250 MMscf/d. Very, very high production. We took the FID. We had the FID from August discovery, February FID. Five months we took the FID of Zohr.
Everybody said, "With two wells, you are crazy. How you can be sure about your reserves?" Everybody say, "No, it's not possible." We could do that because we own 100% of the block, for that reason, we try to have an exploration because we are successful a large stake. Not only because we want to apply our dual model itself, but because we want to be effective. If we were with other two, three, four, five companies, it was not possible to apply our process, our procedure. We have to wait for two, three, four years. Normally, when you drill a well, you drill the appraiser, the exploration, you wait two, three years to get the FID. You are very happy because I'm sure, I'm safe.
There is a big maturation of the project, you are losing money because you put money in your exploration, you wait three years to have your FID. You are losing money. We are losing money. Our investors are losing money. For that reason, we say, in exploration, we want to have a high stake. Why? Because we are quite sure that we are successful. We take this risk, we give value, then we sell. Especially because you want to go very fast to the FID. I don't want to sleep. I want to go to the first oil as soon as possible, want to use our procedure. That is the reason why. You can see after back to back, we drill our other six wells, seven. Now we drill seven wells. Each well is an appraiser.
As I told you before, each well go back to the reservoir model and try, through iteration, to improve your feature, your model, and your engineering model. That now what we are going to do is probably in two years, two and a half year, 2.3 years to get the first production. Our effort is to reach next year, by the end of next year, the first production of Zohr. That is a first production that is not a full field production. That is another things that we apply in our development. To reduce costs, we try to avoid to have all the costs up front, wait seven years, all the development, super wonderful development, you put EUR 10 billion, EUR 12 billion, you start recovering. No, what we are doing. We are doing all our project by phase.
We start with a phase. In this case, the first phase, we have our cash flow. We start being cash flow positive. Then we have the second phase. We reduce our upfront investment. We increase our internal rate of return. We increase the NPV of our project, we reduce the risk because during the first phase, we can fine-tune the model, we can optimize the investment for the second phase. It's practically is in a full iteration that continue and continue until we are not in a plateau situation for the field. That is what happened for Zohr, we can see, I already mentioned some of these projects. For this project, we practically used, or we used the same kind of model. Design to cost starting from the exploration. Here we have the result.
We have from the discovery to the FID, on average, two years. The standard of the industry is three, four years. Then we have from the FID to the startup, to the first production, two and a half years. We have an overall average that is, I think, much better of the average industry of 4.5 years. That is made from different kind of project, is an average. Not all these projects are super giant, but I think that this project that I put on this slide as our giant. That is the difference with respect to where we are in the past. We change completely. We improve the upstream. We improve in term of cost, but in term of time to market and discovery, and we link together all the process. If we go ahead to the next slide.
Looking at the project I mentioned, that is just a small part of our package, but the more relevant in term of dimension of the fields of the reservoir. You see that is what they are going to produce as a cash flow in the next two years, 2017, 2018. At the plateau of this project, they are going to produce about more than, sorry, 500,000 barrel per day. That is practically one third of our production. With this price, that is our budget price. This year we have EUR 43.5. It's not the real price. The real price is higher, fortunately. Then we have, in 2017, $50, and 2018, $60. In 2018, this project at $60, they are going to produce, sorry, EUR 4.3 billion of operating cash flow. Cumulative, we have EUR 7.7 billion, but with this price profile, that is very low.
If you look at the cash per barrel, we have at $60, and that is very important. We have at $60, $30 per barrel of cash flow. Each barrel value is $30. We have to think that $110, we had about $28 per barrel. Before, the old Eni, at $110, had a cash flow per barrel of $28, and now at $60, this project has a $30 per barrel. We improve. We double the value of each barrel. What I told you at the very beginning, that is the reason. We can go to the next. Okay. That is what I said. Here, we talk about, for the first time, we give a projection outlook for 2017. You see what is going to happen? That is our CapEx profile. We are reducing our CapEx. That was the value 2016, that still is close to EUR 8 billion.
Then we have 2017, we're going to reduce further our investment. This investment 2017 is before the disposal. There is no Zohr disposal, but we are increasing the production. In 2017, we are going to have an average production of 1,840,000 barrel per day. That is very close to our record production ever, but it will be the average, with a CapEx that is in strong reduction respect to the 2013. That is the value that we wanted to create. We want to really, in this difficult period, to be able to reduce our investment, because you must reduce your investment if you want to be cash neutral. We wanted to increase our production, to increase the value of our asset, and that's what happened.
From the other side, that is now important KPI, that came from the exploration, from what I told you before. We have been able in this period, but especially in the last couple of years, to increase drastically our replacement ratio, reserve replacement ratio. You see, here we put our official data, what happened to the major in this period. The major cut investment to reduce cost, but they reduced the activity, so they reduced the capability to replace the P1. You saw that we increased our 250,000 per barrel, but we increased our P1 of 1.5 billion with our exploration, so organically, and that is the result. We have a range.
We are going to range also in the future between 120%-130% of replacement ratio, and that is a very important parameter that give the health of the company, and that is impacting the balance sheet, but is impacting also the capability to grow. We have to remember that with what we found, we still have seven billion that are 2P, 3P, that in the future will transform in P1. Now we reach the conclusion of our presentation. I want just to give you an overview of our portfolio and the value that we unlocked through the two main tool that we have really to our portfolio management and disposal. One is the transformation. We transform our business. We want to be an integrated oil and gas company, a pure integrated oil and gas company. We have a lot of value inside us.
We have already expressed in this first phase some value, EUR 10 billion, because the consolidation of Saipem, and then dispose of a Galp , produce EUR 10 billion. That reduce our debt and improve considerably our leverage. That is structural and is not finished. We have the dual exploration model. The dual exploration model is what I didn't explain during the presentation, but it's quite clear, is the fact that we are successful in exploration. We are specialized in exploration like a pure explorationist, we take big stake. Stake means 80%-100% of the blocks. We give value, we reduce our participation. We keep at least 30%, 40%, 50% in the operatorship, the ownership of the development, but we give a lot of value.
This structural model already gave us in the last two and a half years, three years, €5.4 billion, so more than $6 billion. That are mainly made with Mozambique, first phase already done. We have a second phase under disposal. Zohr, that in two months, we finalize with BP, and we announced yesterday with Rosneft. They got 30% plus an option 5% that they can get by the end of 2017. That is our model, and it's something we promised, and something that we got, and we are absolutely satisfied that we have been able to finalize before the year end. The conclusion, here you see practically the picture of what Eni was in 2013 and what Eni is now.
The figures are very good. There is a strategy, there is a transformation, there is a structural model, especially a new kind of model you saw for exploration and for development, then for production and for the cost efficiency. That are the figures. What I like to tell you that I said at the very beginning that we are at the stage 1. We still have a lot of things in front of us. From a structural point of view, we have to really continue to fine-tune and create value from our structure, so becoming an oil and gas company. We have other things to do, that will be done in the next couple of years. We have still to fine-tune our design to cost model.
We just started one half year ago with this design to cost model, with exploration and development. I think we can improve. We want to continue to grow organically. We want to continue to have asset management on the exploration, through the exploration, to create value, to increase anticipated value, not just through the FID, but also to getting money and cashing in before the production. Mozambique cash money seven, six years before the production. That means that we will never be cash neutral during the development. We reduce our exposure. We reduce our risk. That is a very important fact. The dual exploration model is not just a way to cash in money, but it reduces your financial exposure. You reduce your country risk. That is really a part of our model.
We have to, I think, work again, work for a while, because we learned a lot in this period, because maybe we have been defensive in terms of cost efficiency. I think that cost efficiency must become a skill of our company, not just a defensive attitude. It must be a skill, so you can really survive, or more than survive, also very low cost. I think that we are ready with this model to improve our $50 cash neutrality. That is something that really we want to do in our company, not just me, but all our top managers want really to be able to reduce this EUR 50. We were at EUR 127, now we are at EUR 50. We want to be still more robust and have a lower value.
That is what we are going to do. I hope that we'll be ready to present in 2017 a more challenging target. That is very important because it means that we can cope with a very low price, because now we know that the price can be lower than EUR 50, than EUR 40 maybe. We must have a company that can really challenge this kind of price and stretch the dollar, stretch the barrel, be able to make money also with a lower price. With this kind of structure that became permanent structure, you can really get all the value when the price is higher. We are working on that. The phase 1, I think, showed very excellent results. Now we work for the future. We are ready now for the Q&A.
We have still an infographic just to show you the future projects, then we start with the Q&A. Thank you.
Thank you. We are now ready to start with the Q&A. Just a few instructions before. Okay? Together with Claudio, there will be the top manager ready to answer to your question, Massimo Mondazzi, the Chief Financial Officer, and Massimo Mantovani, Chief of Midstream. After collecting the question from the floor, we will have a session with a few questions from the phone, then I will leave the floor to Erika Mandraffino, who is the head of Media Relations, to have the question time with the journalist. Thank you. Please state your name before asking. Thanks.
Great. Hi there, it's Mark Offler from Jefferies. Thanks for the presentation, Claudio. I just have two questions. You referenced the 7 billion BOEs of resource that's still 2P and 3P. Could you maybe give a bit more clarity about what those resources, which projects they relate to, and any timing around FIDs and moving that closer to production. I just wanted to come back to your comments on Zohr, and how you anticipate that to be cash flow positive at each of the subsequent phases of production. Can you talk about how long you might expect it to take to recover those costs from phase 1?
Okay. The 7 billion that we mentioned about 2P and 3P are mainly we have in Congo. A huge part of that are in Congo and in Mozambique. Why Congo and Mozambique? Because Mozambique, now we are going to sanction Coral. Coral is more portion of all the big reserves that we already have there. Most of that are 3P, so discovered, we studied, we test, but are still 3P, and that's a huge amount. Also in Congo, we discovered, as I told you, 6.3 billion. What happened? 3 billion, and we are just 2 phases of Nené because we are working on the gas treatment. We don't want to flare gas, so we are working on the gas treatment storage in M'Boundi, that is onshore. So we are going to inject gas in M'Boundi, and that is a project, and we will be able to increase production.
Transform these reserves in the third phase on Nené in P1 and 3P. We have also the Ghana project where we start with the oil, but we have also the gas project. The gas project will be start after six, eight months. We still have 2P reserve there. We have Nooros. Nooros, we have all the project. Nooros, it is more percentage is still 2P reserves because we developed the offshore. Now we are appraising the onshore, where we have still 2P reserves. We have Johan Castberg, where we have a 2P reserve because we don't have the FID yet. Also Jangkrik. Parts of the Indonesia, of the 70 TCF, there is a part, I think two third, that are still 2P and 3P reserve. That more or less is how they are distributed. For Zohr, what about Zohr?
Zohr, in absolute terms, not for us, has maximum exposure by the end of 2017. We start producing 1 billion standard cubic feet per day. We start our cash flow, we start recovering our cost, and that is the maximum exposure. They go down, I cannot tell you precisely, but with this kind of contract, it depend on the oil price because in Zohr we have a gas price that is linked to the oil, but it's an interval. We have a floor and ceiling. It depends. With a higher price of oil, we can recover faster because it's a PSC, and I think that in five, six year, we can recover completely all the cost.
Our point is different because practically, we don't have a negative cash flow because we already cashed in much more the money we spent and reduce our capital profile for the future. With this money, we can reach, we can cover, we can bridge the 2017 arriving to the new investment with cash flow but without negative impact on our cash. Additional question?
Hi. Peter McNally with Kingdon Capital. Doing all the exploration and subsequent work in parallel as opposed to sequential, can you envision a situation where you're constrained by the number of people you have or the industry services if all these activities are going on at the same time? Then a second quick follow-up, does your 2017 guidance contemplate any OPEC curtailments?
That is a good question. Also the first one was good, but otherwise my investor. It's a good question. All your questions are good. I say that, it's finished. That is true. That is true, and it's clearly now, we had a very good period because we have been practically one of the few company that has been engaged with FID, new projects. We are developing, investing everywhere, lower cost, and we have contractors, a queue, a long queue of contractor ready to work. We change something that I forgot before, but we change our model from a development and a contractual strategy model. We have much more people. We change our development. We insourcing people. That while the other were outsourcing to reduce cost, we insourcing people.
We don't cut any head. We still have the same kind number of people, more than we had in 2013, because we thought that we need people to run and to have a strong grip on our project. What happened? We changed the EPC contract. You know that in EPC contract, you have the main contractor that is a third party, is a contractor, then you have the different packages, so subcontractors. What we have done is, we source people, we create a very large engineering base, and we have two big group in Milano, one in Rome and one in London, and we are working as main contractors. We change our EPC contract. Probably in all these contract, the main contractor is Eni. We have our people there. That is a partial answer to your question.
Also, if we increase the number of project, we are in different market situation. The main contractor will be Eni, because we want to have a grip on the cost and on the time to market. Also in that, we are unconventional. We went in a different direction, say, "You are too expensive." We are not too expensive. You are too expensive when you delay your project of 10 years or 5 years, and you are over-paying and spending. There you are expensive. The people is more percentage and are people of your company, with your know-how, with your culture, with your attention of the cost efficiency, and that what we have done. It's a partial answer because you cover just a part. Clearly, you must really run advance and try to have good contractors. When you work on the reservoir modeling, my people.
When you work on the EPC, on the fields, our people, conceptual, our people. The detailed engineering is not completely our people, and the construction is not completely our people. That we can have a bottleneck, and there where we have to be very effective, efficient in the contractor strategy. Yeah.
Budget and the topic of OPEC.
I think that the OPEC impact will be very marginal for us because it's regarding just Kazakhstan. For Kazakhstan, for what I saw is a question of 20,000 barrels. Kazakhstan a huge production, different fields. I don't think that they are going to reduce production in Kazakhstan, because KMG is tied with us, and we are really, we need to recover money. I think that in the other part, in Libya, where we produce a lot, there is no restriction. In Nigeria, the same. In Russia, we are not in Russia. We're not in Saudi Arabia. We're not in Kuwait and the Emirates, it's really marginal. Okay. Someone else?
Natalie Trata with UBS. Just as a follow-up to that question as well, can you remind us what your CapEx plans are for next year, and in general, what the CapEx trend looks like in the coming years? As you look to, obviously, counter investing versus some of the other companies in some of these projects, have you been able to take any advantage of lower cost in this cycle as you look into CapEx going forward, in addition to OpEx?
Yes. I cannot be very precise about CapEx next year and the following years because will be one of the main subject of our strategy presentation in March. I can't anticipate something that I have to present first to my board, not yet presented. I just gave you a figure that is going down. You saw that it was close to seven something, seven point something. That was 2017 with an increase of production. That what I can say that is before disposal. I cannot tell you, but you can get very quickly what is the impact for us for Zohr disposal in term of CapEx 2017. That is the answer there. For the supply chain, yes, we got some advantages.
When we remember that we talk about 33% of cost reduction in the last couple of years, or 25% of this 33%, more or less 10%, is due to the supply chain. We got very good conditions and discounted prices in the drilling, offshore drilling, deep offshore drilling, the service is much less, is 10%-15% of discounts. In the vessel, good discounts. In the project, not so much, also because our people is running the project. I think that that is the figure, 25, and I think now is that plateau. I don't think that we can get much more than that. Also considering now the OPEC cut and the production that is growing. What I imagine that not all projects, but some project is going slowly to start up again. Okay, thanks. Someone else?
Shaya Berzon from 1919 Investment Counsel. To what extent do you think this opportunity to leverage kind of brownfield infrastructure around the world and create these very quick time to market projects? How much running room do you have to continue doing that in the next few years? To what extent do you start exhausting those opportunities and need to start focusing more on true greenfield in the full sense?
Thank you for the question. First of all, our greenfield or back percentage is 30% now. We have 70% of the brownfield and 30% on the greenfield. We are moving to a 40% in the next year because we reloaded our exploration, we have more greenfield. We touched just a very small percentage of our existing facilities because if you look at what we have done, it's really Congo and Egypt. We still have Nigeria. There is a lot of facilities, a lot of infrastructure where we can't really get profit. We still have Libya, we have Algeria, we have Italy as well. We have Indonesia or Pakistan. We are running exploration in different countries.
We are running exploration in not only where we have facilities, but where also other company has facilities that are empty or underutilized, that for them is good because if we have production, they can reduce their operating cost. Egypt, we have a huge amount of facility. The grid is very big. We are using synergy in the near future with Israel because we have at least two fields, one Israel and the other in Aphrodite in Cyprus. We are discussing where they can use the existing facility in Egypt. I think that there are a huge amount of opportunity, not just for us, for everybody. Think about this facility to create value. You must be successful in exploration. You must have some gas or oil to put in this facility. Really we just cover a small part of the high potential that we have worldwide.
Hardin. Hello? Hardin.
Yeah, reach now.
Hardin Haskell, Dominic Onderdrix, here it is. Half a question on help, half a question on a problem. Do you think Tillerson as Secretary of State, knowing the industry really well, being a peer, would be helpful in lowering tension in certain areas of the world where Eni operates? You think that will be of help? The other question is on a possible obstacle. Eni has had to deal with many Italian governments, and another one just changed. The Italian government is part of Eni. Has that been an obstacle on your model, on applying your new model?
I talk first about the Italian government, I think that if you look at the result we got, there is no obstacle because that is really an operating model. I report to my board. I report to all my investors the same way. If there is strong obstacle, and something that I cannot do, I change. I want to get profit and I want to be 100% responsible for my activity, to answer to my investors. I can tell you, I look at the result we got, that are absolutely, I can say, very positive as compared to the past. We don't have obstacle. I think that everybody help us and follow us, and not just in Italy. All our investors, also analysts, I think that our position improved a lot because I think people appreciate what we have done.
Talking about Rex, I think Rex is very experienced. He's a very good listener, very good negotiator. I know him very well, and for Kashagan also, for other reasons, we have a lot of activity in Nigeria, in Angola, in the U.S. I think that he can give value everywhere. He knows everybody. He's very respected. I think he's a good character. He's a good listener. He's a person that can find compromise. Because he creates so big value in the past, that means that he's able to find solution and not create problem. My answer, yes, I think that will be very positive.
Okay, I will collect just few additional questions, then I will open the calls from the phone, if any. Okay, if there is some calls from the people who is attending by phone.
Yeah.
That is the question? I didn't understand very well.
Sorry, the first question conference call comes from Thomas of Swiss. Mr. Ravu, please.
Good morning. Can you hear me?
Yes.
I have a question, please. First, I guess, on your third-party gas trade, your strategy to be more Upstream focus, you intended gas to be part of future Eni. I wonder, explain the strategic rationale to these supply contracts, and whether you can see scenarios whereby the third-party replaced entirely equity gas. The question I have is on the Sonatrach contract renegotiation. This will move you structurally into break-even. Would it still be break-even without having to renegotiate the contracts with Statoil and Gazprom in a rising oil price environment? Thank you.
No, thank you. Unfortunately, well understood the second question. I cannot answer the second question. The first question, I didn't understand anything. I just say something about Sonatrach, but the first question I didn't understand because I don't know if somebody in the room, the audience, understood what he said. I answer the Sonatrach question then if you are so kind to repeat the first question. Sonatrach, no, I cannot tell you the value of the Sonatrach renegotiation. It is clear it is a very good one. It is something that for 2017, by the same condition, can be translated and put until the end of this contract, that is 2015. Meanwhile, we are discussing with Sonatrach. We start the discussion with Sonatrach for what is going to happen after 2019. There is really a very good dialogue with them.
The break-even is not made just by the Sonatrach contract, but also by, as I said, the logistics cost. We are working on the logistics cost, that is storage and transportation in Italy and abroad. We still have EUR 150 million that we have to recover. The overall package, Sonatrach plus that, and we can add some add value also with the logistic, with the Statoil contract, will deliver the break-even. That I can tell you already in our pocket. If you are so kind to repeat the first question, please.
Okay. Let me try again. You said in gas and power, gas retail is non-core, but your third-party gas supply contracts to be part of Eni in the future. My question is, perhaps you can explain the strategic rationale to hold on to these third-party supply gas contracts, and the other question around that is whether you can see yourself in the future replacing all these third-party gas contract with equity gas. Thank you.
Thank you. Now I understood. The third-party supply contract are long-term contract. We have a contract, and we have to respect the contract. Clearly, my objective is to really work just with our equity gas. We are a large position in gas, and that is done in Italy and through our LNG, like Nigeria, like Angola, and in other parts of the world. That is the trend, and that's what we want to do, and that surely is where we can get more profits and margin. For the other, for the third-party contract, we have GasTerra that is going to finish. We have Algeria, 2019. In Algeria is a third party, but we are producing gas, and so we have part of this gas in MLA, Kafka, and I hope in the future also in the TIGAS, that is part our gas.
In Libya, it's 50/50, it's our equity gas. We remain with Statoil and Gazprom, but that are long-term contracts. I'm obliged to work and rework to align this contract to the hub. We got it for a period. Now we see if we can really change the structure of this contract, and permanently have some link, close link to the hub, or continue to renegotiation. What I can tell you is that I cannot stop this contract because they are contract that last for other 10, 15 years. Okay. We could take another one.
From Mr. Jordan of Exane. Mr. Jordan, please.
Yeah, good afternoon. 2 questions, please. First, could you talk about whether you think is the right interest in Zohr for development, and what do you think the new partners, Rosneft and BP, bring to that development? My second question is just if you could give an update on Mozambique, please, particularly in terms of project financing, but also a sell down in the stake. Thirdly, as we look into 2017, could you talk about the role of Saipem in the Eni group? Thank you.
Thank you. Zohr, the role of Rosneft and BP, before buying these or acquiring this stake and share, they ran a deep due diligence, months of due diligence, especially BP, more than one year of due diligence. They know exactly everything about investment, future investment, and they accepted all the program investment in term of development and in term of exploration, because we have some huge upside in Zohr in term of exploration. I don't think that there is any problem from that side. Saipem role. The Saipem role in 2017 will be what has been in 2016. We are a shareholder. With the consolidated debt, so we don't have any more control on Saipem. We have the shares. We have still a huge value because we have more than 30% of shares of Saipem, they are there.
At the moment, we don't think really to touch this share because we think that it's big value, big value that is growing. Is already growing now, but it's growing with the oil price. Is growing also with the new organization of Saipem, with the kind of new project that they acquire. Saipem, the same role than 2016, what I think more value in 2017. Mozambique, an update on Mozambique. You want to, Massimo, give an update on Mozambique? Thank you.
For an update on project financing for Coral, what I could say that the project is quite ahead. We are finalizing the agreement with the banks. We are talking about a huge amount of project financing that will be in the range of EUR 5 billion, probably the biggest we ever made in our history. The agreement should be finalized, I guess, by January. In the meantime, we are waiting for the finalization of the internal process, authorization process of the other partners.
Interesting.
The Mozambique party already gave his okay, and we are waiting for the Chinese, the Portuguese, and the Korean. That is expected in the weeks to come.
Just two other more. No more?
Next question comes from Mr. Ash Borgataria. Ash Borgataria, please.
Yeah, go ahead.
Hi, thanks for taking my question, and hopefully you can hear me. The first one was just a quick one on the financial framework. What oil price do you need in 2017 to cover both CapEx and dividends? I think you said before $60, but it looks today like your CapEx guidance has come down a little bit. An update on that would be useful. The second question, just going back to Mozambique, can you talk about why it makes sense to do Coral as a separate development to the joint onshore development? Whether you can give any specifics on, or just remind us about the CapEx guidance for Coral. Thanks.
For first question, I don't talk now about the $60 because that is another issue that will be disclosed and which we are going to elaborate in March during our strategy presentation. It's clearly, we increase production, and we are reducing CapEx, that means that we are in a better shape. For Coral, when you start a green project, a green country, and you have to create a gas market, you start small. You cannot start with big investment. Otherwise, you can be stuck. What we prefer to do, because it's a green field, to develop offshore, we don't have any big problem onshore. That is more difficult because there is no synergy at all, so you can't be faster. Secondly, you have to create your market, and we succeeded.
A first project in a big LNG project is really, it's not a pilot, that is not a pilot, but it is really a break ice. We break ice and create value, give credibility to the country, to the market. BP made a very long assessment, honestly, in this case, more than one year, from a technical point of view, contractual point of view, talk with the authorities. You have to establish the right environment for the big investment. That is the reason why we prefer to start with Coral offshore and not with the big problem, as I said before, because you want to go phase by phase, and we want to have big upfront investment. That is the old model that create 127 for the industry was $110, $150 cash neutrality.
Okay, the last one, please.
We have no more.
No more? Okay.
Okay, thank you.
Now I thank you.
Finished. Thank you very much.
We will now move to the next room for the buffet. I leave the floor to Erika for the question time with journalists.
Okay. Thank you very much.