Good afternoon, welcome to our full brand strategy presentation. Today, I'd like to start by showing you a short video about the milestones and the results we have achieved so far that confirm the ongoing execution of our strategy well ahead of schedule. The strategy we presented in July 2014 was based on four key pillars. The restructuring and transformation of Eni into a fully integrated oil and gas company, the consolidation of profitable growth in all our business, the turnaround of the mid downstream, and the major cost efficiency program, which was already underway. Thanks to the continuous efforts and the strong commitment of our people, I'm glad to report that all of these key milestones have been achieved in advance. We are now a leaner, more efficient company. Through this action, we were able to enhance financial flexibility and create value also with the low oil prices.
What is today's challenge? It is surely the dilemma between short-term cash balance and long-term growth. The industry needs to face this very complex challenge to reduce costs, to fulfill short-term financial targets without destroying long-term value. Today's scenario is characterized by a gap between oil prices and costs. Since the second half of 2014, the oil price has fallen by 70%, while the costs have decreased by only around 25%. There is also natural uncertainty surrounding the recovery of oil gas price. Due to this volatile situation, we have revised our scenario, taking into consideration a slower recovery. How can we cope with this scenario? The industry has reacted by cutting CapEx by more than 35%, postponing or canceling projects. This is a short-term solution. It's not viable for the long run because it will impact on long-term growth and asset value.
The only solution to reconcile long and short-term goals is to rapidly align cost and prices in order to continue to profitably invest also with the oil prices low. Eni is in the right position to meet the short-term financial constraints and long-term perspectives. Why is this? Because we already have a competitive cost structure, which is based on two main levers. We have an asset portfolio that is profitable even in low scenario, an efficient operating model which aims to continuously revise contractual terms and reduce costs in the supply chain. First, our asset portfolio. This has been founded on exploration, where in 2008, we decided to strategically invest, developing internal competencies and proprietary technologies. This was the first step in building a resource base focused on conventional assets at a very low cost.
Since then, we discovered a huge amount of resources, this allow us to have main competitive advantages, such as a low-cost base, limited exposure to complex projects, a diversified asset portfolio which give us the flexibility to optimize investment decision and spending, the capability to anticipate cash flow and reduce CapEx by valuing stakes where we have a high participating interest. This is what we call our dual exploration model. This distinct operating model is also characterized by high level of operatorship. This puts us in a position to strictly control costs as well as a continuous optimization of our supply chain so that we can reduce both CapEx and OpEx. As a result, the average upstream cost for our new projects was reduced from an already low $30 per barrel level of 2014 to around $20 per barrel.
This attractive cost structure is built on exploration cost of less than $1.5, OpEx of $7, and CapEx of $11 per barrel. Another crucial aspect of our operating model is the outstanding result in safety and the environment, which remain our top priorities. In safety, we were the best performer in the industry for the last three years. Our 2014 total recordable injury rate was equal to 0.7, 43% lower than the peer average of 1.24. In 2015, we further reduced this by 37%, reaching a notable value of 0.45. These results show our commitment to improve our safety performance, targeting a zero level of injuries every year. Regarding the reduction in greenhouse gas emissions, we have defined an action plan that will reconcile short and long-term goals.
This is mainly based on focus on conventional projects, which are characterized by lower emissions and increasing exposure to gas; driving down energy efficiency projects, which increase gas volumes available for the domestic market while reducing energy consumption; the greening and conversion of the downstream business, which also gives us the opportunity to recover profitability for weaker assets; the adoption of a carbon price sensitivity of $40 per ton on all our major developments to pursue efficiency right from the early planning stages of the project; and finally, we have recently set up the Energy Solutions business unit, which is dedicated to identifying and implementing growth opportunities in renewable energies. In the period 2010-2014, we reduced GHG by 27%, from 59 million tons CO2 per year to 43 million tons CO2.
In the Upstream sector, we reached a level of unitary emission of 0.2 tons CO2 per ton of equivalent production, and for the future, we are planning to further improve these levels, targeting a 43% reduction of unitary emissions by 2025. Now a look at our targets. The overall target is to further enhance our cash neutrality during the four-year plan, where operating cash covers CapEx at $50 in 2016, and both CapEx and dividend at $60 in 2017. To reach these targets, in Upstream, our production will continue to increase with an average annual growth rate of more than 3% in the four-year plan. The cumulative growth rate of 13% to 2019 will be achieved despite an 18% reduction in CapEx.
In Exploration, we'll focus on near field and complete the assessments of the discoveries made in recent years with the target of discovering 1.6 billion barrels at a unit exploration cost of $2.30 per barrel. In Gas & Power sector, we expect a structural breakeven from 2017. In Refining, we confirm a lower breakeven of around $3 per barrel in 2018 with the existing capacity. In G&A expenditure, we increase our cumulative saving in the four-year plan from EUR 2 billion to EUR 2.5 billion, thanks to additional cost reduction, logistics and operating efficiency, and in streamlining organization. On disposal, in 2015, we cashed in EUR 7 billion, out of the EUR 8 billion that was targeted for the entire plan. We have now increased our four-year target, and we will dispose of EUR 7 billion of assets, mainly through our dual exploration model.
More color on the plan for the different businesses, starting with Explorations. Here, a short video showing our recent discoveries. Exploration has been the strategic driver behind our low-cost organic growth. Over the last eight years, we have discovered 11.9 billion barrels of resources at a unit cost of $1.20 per barrel. We discovered 2.4 times the raw material produced in the period, far above the peer average of 3. Zohr is our latest supergiant discovery, the fifth in the last five years, all of which are located in different basins and two new plays. Out of 11.9 billion barrels of resources discovered so far, we have promoted around 8.5 billion barrels of exploration resources to 3P reserves. What will exploration give us in the future? Exploration is the foundation of our growth, our very low-cost structure, and competitive time-to-market startups.
Our discoveries will contribute more than 500,000 barrels per day of equity production in 2019. We will promote around 3 billion barrels of proven reserves. Many exploration activities will be concentrated in North Africa, West Africa, and Far East. In the four-year plan, we will drill 94 wells in 25 different countries, targeting 1.6 billion barrels of resources. This maintains our average annual exploration spending of EUR 900 million, in line with 2015. Following this strategy, in 2016, 50% of our exploration spending will be dedicated to proven basins and appraisals, while 30% will be invested in near-field explorations, and 20% in frontier plays. Development. I'd like to highlight that each single project in the four-year plan comes from our exploration discoveries. If you exclude Goliat and Kashagan, all the other startups are the result of fast-track development of the last seven years of our exploration.
All these projects are remarkable for their short time to market. Examples are Angola Block 15, where we developed a deep offshore field in different phases, only four years after the last discovery. Egypt and Congo, where we reached first production within one year of the discovery well. Now some color on Zohr, where we are and what we are doing. Zohr is the best example of our strategic approach and operating model. Here we discover a supergiant, a new play located in a mature area and close to existing facilities. It is a gas field of estimated 850 billion cubic meters in place, lying in about 1,500 meters of water depth. We reach FID only six months after discovery, a remarkable result. We are well on track to start production by the end of 2017.
We are well in advance in the procurement process for offshore long-lead items, such as vertical flow lines and subsea wellhead. We are progressing with the civil works for the onshore treatment plant. To reduce cost and financial exposure, we will develop Zohr in an accelerated startup phase, then a fast ramp-up to production plateau. The accelerated startup phase is up to 1 billion standard cubic feet per day from six subsea wells that will be connected to shore through a new gas line. The ramp-up phase will reach 2.7 billion standard cubic feet per day from 2019 through 14 additional wells. CapEx for the two phases is planned to be below EUR 12 billion. The gas will mainly be sold on the Egyptian market. We have already agreed a contract price formula and securitization for sales payment.
The Zohr project is regulated with a PSA, and at plateau, it will contribute more than 400,000 barrels per day to our equity production. We have just successfully performed the production test of Zohr-2S, the first appraisal well, which confirms excellent reservoir characteristics and has an estimated deliverability in production setup around 250 million SCF per day, about 46,000 barrels per day. Let me move on now to production growth and here is a short video. All the projects that we have just seen give us a cumulative production growth of 13% to 2019. In 2016, we will reach a production growth of more than 2% versus 2015, excluding the one-off items that occurred last year and which amounted to 42,000 barrels per day. By the end of the plan, start-ups and wrap-ups will contribute around 800,000 barrels per day.
These will come mainly from North Sea, North and West Africa, and Far East. We will operate around 90% of the new start-ups so that we ensure tight control of cost, timing, and quality in our projects. In the next four years, our operated production share will remain high at a significant level up to 75%. In the long term, 12 large projects with more than 6 billion barrels of equity reserves will sustain our production growth. For 2016, we have already taken the FID for Zohr, and we target a final decision also for Coral. Furthermore, in 2017-2019, we will sanction main development projects in Congo, Nigeria, and Kazakhstan, and we will take the FID for Mamba. As I said at the start, a strict and constant revision of the supply chain is the other key lever to align costs to prices.
Through this, we aim for a saving of EUR 3.5 billion in the four-year plan on a total contract base of more than EUR 20 billion. We started renegotiating contracts in mid-2014, and last year alone, we achieved a saving of EUR 500 million. These represent a combined saving of 18% on roughly 2,000 contracts for renegotiation and tenders. All of the plan, we will accelerate cost deflation by continuing with the renegotiation, bringing forward tenders, and refocusing our activities. The biggest improvement area is in the deepwater projects, where we have obtained major savings, not just for drilling rigs, but also for the supply of goods and installation contracts. The daily cost for drilling rigs will be halved from $9.2 million-$4.5 million. Further additional savings will come from services in logistics and maintenance, bought materials, a new contract strategy for EPC contracts.
Based on the huge discoveries, we now have more flexibility to accelerate production while lowering expenditure. In upstream, excluding Zohr, we will reduce total CapEx by 39%. If we include the investments for Zohr, which substitutes more complex and expensive projects with start-ups beyond the four-year plan, the CapEx reduction is around 18%. In particular, upstream CapEx will be reduced by around EUR 18 billion through the ongoing revision of portfolio activity, including rescheduling of projects in Norway, Venezuela, Iraq, Indonesia, and revision of scope of work for a total of EUR 14 billion, and the renegotiation of contracts with an overall impact on new projects of EUR 3.5 billion over the period. Net of the CapEx associated with the disposal program, we decrease total company expenditure by 21% versus the previous plan to around EUR 37 billion. Upstream spending will be 90% of the new total.
Now let me give you some more detail on our project breakeven, which is the result of our effort to reconcile costs and prices. Thanks to the recent huge low-cost exploration discoveries, synergies with the existing assets, the focus on project standardization and modularization, and the strict attention to supply chain, we reached the outstanding result to lowering the average breakeven of our project from $45 per barrel to $27 per barrel of Brent equivalent 2016. This breaks down as follows. For onshore projects, around $15 per barrel. For shallow and deep water projects, around $30 per barrel. This crucial result is key to being able to tackle the low scenario and be in the position to continue to grow profitability by capturing all the future upside. Now, where we are and what we have done in the turnaround of the midstream.
The progress in the turnaround of the Gas & Power business brought us close to the breakeven in 2015, even without the contribution of GasTerra arbitration award, which is now expected in the first half of 2016. In the four-year plan , we continue to increase profitability by focusing on long-term contract renegotiations, improved sales channels, and greater operating efficiency. Contract renegotiation will help us to complete the full alignment to market conditions. There will be a reduction in contracted volumes, which will bring more flexibility in the portfolio. We will also explore the true value of our synergic sales channels, expanding our retail customer base by 20%, taking greater advantage of trading, and benefiting from the flexibility provided by our LNG portfolio. We will continue to be focused on right-sizing of the operating and logistics cost base, saving EUR 350 million per year from 2019 compared to 2014 levels.
Gas & Power will generate a cash contribution of nearly EUR 3 billion over the four-year plan . We will reach a positive EBIT in 2016, growing to nearly EUR 900 million by the end of the plan. Gas & Power structural breakeven is targeted from 2017. Now Refining & Marketing. Our main target for refining is to lower breakeven to around $3 per barrel in 2018, maintaining the current refining capacity. Over the past three years, we have reshaped our European portfolio by increasing production efficiency, exiting or converting loss-making assets, reducing refining capacity by one-third, and rationalizing logistics. This allow us to reach EBIT breakeven in refining in 2015, two years ahead of plan, thanks to the reduction of our breakeven margin to about $5 per barrel. Downstream is now much leaner, and will not be required to make further capacity cuts in the near future.
Looking ahead, we will focus on maximizing the conversion of the barrel, taking full advantage of Eni's Slurry Technology plant in Sannazzaro, where we are progressively increasing our production levels. We will also complete the conversion of loss-making assets into sustainable green businesses, further enhance efficiency on operating costs, and defend our retail market share. This will grant economic positive results during the Three-Year Plan, reaching an adjusted EBIT of EUR 700 million in 2019 and a cumulative operating cash contribution of EUR 2.9 billion in the plan period. Now, I leave the floor to Massimo for financial highlights.
Thank you, Claudio. Good afternoon, all of you. First of all, I'd like to emphasize both the historical and prospective cost performance in our main business, the upstream. In terms of OpEx, in 2015, we reduced our unit cost by 15% to $7.2, almost doubling the original reduction target of 7%. This, I believe, further strengthens our industry-leading position in this metric. In the following years, we expect to further reduce OpEx as a result of contract revisions, additional optimization in maintenance, lower energy feedstock costs, and logistic rationalization. In 2016, we plan to deliver an OpEx per barrel down to $6.4, while in 2019, we are committed to keeping it below $7, notwithstanding the projected scenario recovery and the startups of giant fields such as Kashagan and Goliat, with higher than average OpEx.
On finding and development cost, we achieved a top quartile position through a disciplined approach to CapEx that, as you know, are devoted only to conventional assets. In the coming years, we expect a further improvement on this metric as a result of the CapEx plan just described by Claudio. The related promotion of new proved reserves that will greatly exceed the production, resulting in a reserve replacement of around 120% in the plan period. As a consequence, our funding and development cost is now projected to come back to the levels that we experienced in the middle of last decade. Now a quick video to introduce the update on our disposal plan. Our active portfolio management, as well as cost-based optimization, provide us with further financial flexibility.
One year ago, we launched a significant disposal program amounting to a pre-tax EUR 8 billion to be achieved in 2015-2018 period, with EUR 6 billion anticipated in the first two years. Actually, we have greatly exceeded this short-term target as we have already cashed in EUR 7 billion, including the cash of the now completed Saipem deal. Looking ahead, we expect further material disposals even in this weak scenario. In fact, our exploration assets remain attractive to potential buyers thanks to their high quality, size, desirable location, and competitive cost structures. Therefore, we plan in the next four years additional pre-tax disposal of EUR 7 billion, mainly through the share dilution in recent material discoveries, in line with our dual exploration model.
This new disposal plan is once again front-end loaded, with around 80% of the overall value scheduled in the first two years, envisaging the positive outcome of some ongoing negotiations. Portfolio will also include the continuing rationalization of our position in both mature upstream and non-core mid downstream assets. Now let me show you the overall cash flow effect of our strategy. Upstream sustainable growth, completion of the turnaround in other businesses, cost efficiency, and portfolio management will all contribute to a material improvement in our cash generation. In 2015, the resilient contribution from operations as well as working capital, including non-recurring actions, allow us to reduce our organic CapEx coverage to $50 per barrel.
In 2016, 2017, projecting a lower average oil price of USD 45, we expect cash flow from operations to be in the range of EUR 8 billion per year versus CapEx of around EUR 9 billion per year. This gap will be covered by an additional USD 5 to USD 50 Brent, confirming the balance already achieved in 2015 without the contribution of last year's material non-recurring items. This target is well below the USD 63 guidance we released during our previous strategy presentation. In 2016, 2017, our disposal program is expected to generate an average of around EUR 2.5 billion post-tax per year. Moving to 2018, 2019, the action we have undertaken will increase operating cash flow by 17%, ensuring the full organic CapEx coverage even at the lower Brent floor of USD 45 per barrel.
A rising Brent price to USD 63 as per our scenario, would complement operating cash by an additional 31%, bringing the overall improvement of cash flow from operation versus 2016, 2017 to around 50% above our dividend coverage requirements. In addition, we expect a further EUR 0.7 billion per year from disposals. Uncommitted CapEx for around 40% of the overall investment in 2017, 2019, gives us great flexibility in the event of lower scenario. On the other hand, should the macro scenario be better than expected, significant upside could be achieved thanks to the beneficial effect of the growing production. As an example, a USD 10 higher average Brent price per year would improve average annual cash flow by an estimated EUR 2 billion. Regardless of the scenario developments, we remain committed to a strong balance sheet throughout the four-year plan, maintaining leverage within our 30% ceiling. Finally, our shareholder remuneration policy.
In 2015, we committed to pay a floor dividend of EUR 0.8 per share, with a progressive distribution policy in line with our underlying earnings growth and scenario upside. Today, even in a much lower oil price environment, we confirm our commitment to pay a full cash dividend 2016 of EUR 0.8 per share, thanks to the remarkable operational achievement we have been undertaking, as well as non-core disposals, thus maintaining satisfactory financial flexibility. This commitment is compliant with the two key conditions we assume to test our dividend sustainability: payout and cash neutrality. The payout is expected to remain higher than 100% in 2016 and 2017, penalized by the underlying mix scenario, but should be back below 100% from 2018.
Cash neutrality has been significantly reduced from the previous plan. Now is expected to be at USD 50 per barrel in 2016, including disposals, versus the previous guidance of USD 60 per barrel. At USD 60 per barrel in 2017, excluding disposals versus the previous guidance below USD 75, and finally below USD 60 per barrel, excluding disposal in 2018 and 2019. I will now hand back to Claudio for the conclusion.
Thank you, Massimo. To conclude, Eni has started a new cycle of profitable growth and has the potential to extract more value in the future. Since 2014, we have worked to increase the resilience while fueling value growth. We have transformed Eni in a fully integrated oil and gas company, focused on the upstream business, and we have successfully completed the turnaround of the mid downstream. This, together with the complete revision of our cost structure, means we have become a leaner and more resilient company. The discovery of huge amounts of resources at low cost will sustain our production growth through a pipeline of profitable projects at very low cost break even. This supports stronger cash flow generation, gives us the flexibility to optimize investment decisions, and continue to feed our dual exploration model.
Thanks to our competitive cost structure, Eni is now in the position not only to succeed in this downturn, but to capture additional value leveraging price upside in the near future. As I said at the start, the balance is to how to align cost to price. Eni is in a very good shape to do this, and our current achievement is testimony to that. We are now beginning a new cycle where we will express our full potential, boost our value creation, and increase profitable growth. Now, before starting the Q&A section, let's see a short video about the major milestones and major steps of our four-year plan. Good afternoon. We are now ready to open the Q&A session, so please raise your hand and state your name before asking. Thomas?
Good afternoon. Thomas Adolff from Credit Suisse. Two questions, please. At the start of the presentation, you talked about the importance of managing the cash cycle and returns in the short term, also not to forget about the longer term and to take FID on projects that make sense longer term if you have a positive NPV. As far as LNG is concerned, in this environment, if you take FID on LNG, you commit a lot of capital, so it's really hard to manage your short-term cash flow, cash balance, and your returns. At the same time, taking FID in this environment, LNG projects, also not the best idea because the contracting environment-
It's not one of the best, you said?
It's not a good idea.
It's not a good idea. Okay.
The contracting environment is not so good, which means from an NPD perspective, longer term, you might be also leaving some value on the table. My question really is, where does Mozambique sit in your priorities? The second question, I guess more for Massimo potentially, is the chart you showed on operating cash flow. In 2016 and 2017, you show an EUR 8 billion FFO. I wanted to understand the moving parts from 2015 down to 2016, what's included and what's not. Is chemicals included? Is gas retail included? Et cetera. I better understand the moving parts.
Thank you.
Thank you. So I start with LNG Mozambique . First of all, the plan we presented as [FLNG Coral] , FID 2016, and by the end of 2017, also Mamba. Energy is not a mono-dimensional picture, because energy depends on the upstream cost from one side, and then the modularization and the phases of the whole energy. We discover 85 TCF. We are going to develop the first five or six TCF with the first LNG, that is the Floating LNG . From a market point of view, upstream is very cheap, very low. Drill a well in three, four weeks, need very high rates. You need just a few wells, three, four wells. You can cover the first production. Upstream, very low. From the market point of view, this is the best period to close your contract.
Your supply chain is wonderful from any point of view, because the yards are empty, there is no investment. That is the right moment. If your upstream is good, if you are able to close your gas phase on 15, 20 years, so everything is guaranteed, that is the best moment to close your supply chain. We put it in the plan for us first and the FID, I say 2016. I hope that before June, we are in the position to take it. We got the approval for the POD, plan of development. We closed partly the GSA. Now just we are in a process of internal authorization, and the values are above our hurdle rate. It depends on, there is no monetization. You have to look at all the dimensions inside your project.
Okay, thank you, Thomas, for your question. As far as the cash flow, so the chemicals business is assumed to be among the EUR 7 billion disposals. In this cash flow, we assume that disposition is at the end of 2016. Just 2016 numbers are included in this projection. On the cash flow point of view, I would say, the contribution will be positive and should be substantially equal to the investment that we are retaining among the investment that we are consolidating here. The final algebraic sum will be close to zero. The same cash flow operation and the same value investment. It's inside, yes. To be precise, it would be more or less EUR 300 million on the cash flow operation versus EUR 300 million, including the CapEx as far as 2016. The assumption is disposition at the end of this year.
Thanks very much. Thanks for my questions. It's Hamish Clegg from Bank of America. First up, it was a slightly sort of abnormally high tax rate last year. I wondered if you could tell us how to think about tax this year. I know there was some complications with production sharing, et cetera. One for Matt, right?
You can't look at me, buddy. You're trying to ask.
Sorry. I have one for you, Claudio, actually.
Thanks.
First I have one for Luca, actually, just on exploration. I wondered if you could tell us what the sort of nearer term exploration catalyst might be. How soon are you drilling any sort of material prospects? Are we looking at things like Portugal, as the Gulf guys alluded to earlier in the week, or more folks in the Barents Sea? Finally, for you, Claudio, for Versalis, what rough percentage of the disposal plan could that be? Is downstream restructuring sort of basically finished now?
Okay. We can start with the tax rate, the easier one.
Thank you very much.
Definitely, we recorded a high tax rate in 2015, around 90%. Ed just commented about this result during the fourth quarter conference call. I said that it's due to the strong contribution from PSA, that by definition are, I would say, much more resilient in a low oil price environment. Normally they present a higher than average tax rate. This effect has been combined with negative results in countries in which we retain concession with negative results in 2015, such as U.S. The algebraic effect of this positive and negative result in tax rate and cumulative tax rate came from a mathematical point of view, is even higher than the highest tax rate you pay. That's the mathematical effect of this 90%. As far as 2016, you're seeing we are projecting a $40, so even a lower Brent scenario.
With a lower Brent scenario, the effect I just mentioned would be still present in our numbers. We expect that the tax rate will be even higher than we have seen in 2015. We forecast to be back to a normal tax rate starting from 2017, even at $50. Because of the movement in our portfolio, because new projects, even in PSAs such as Kashagan, with a significant taxable income, with a lower tax rate, because I think Kazakhstan tax rate is 35%, will allow us to be back to much more normal P&L tax rate in the range of 60%. Having said that, I would like to comment also on the cash tax rate. If you remember, probably during the conference call, I had the occasion to comment what we got in 2015. It was a number in the range of 38%.
We expect this number even lower in the coming years, with an average that will be around 25%. This number is the ratio between the cash flow from operation before moves, before changes in taxes versus the amount of taxes really paid in that year.
I have 2 questions to answer. Before giving the floor to Luca, I just want to make a general comment on our exploration. We are in a situation, a position where we discover 12 plus other potential 3 or 4 billion. We are really moving close to our discoveries and close to our existing field to be able to work with a current market that is in the range of 12-24 months. That is what we want. We keep constant the investment for exploration that Eni mine that we want to do and replicate what we did until now. We saw that in the last 7 years, but especially in the last 4 years, we had exploration that has been able to put in production the FreeUp plant 500,000 barrels per day. That is our model.
We have also some peak to our world. We try something more risky, we are working with the POS, with the probabilities of success in our exploration between 50%-80%. Luca is going to talk about the riskier exploration that we have in our plan.
As Claudio explained, our exploration CapEx for frontier exploration has been reduced for 2016. This is mainly for the reason Claudio explained. We have a lot, we have to digest.
Not all of our exploration.
We have some few wildcat in frontier basin this year, two or three, and we will test new plays and new basin, and also we will honor our commitments. This is what we will do in frontier basin this year. Well in the Barents, well in Portugal, well in Angola, that's mainly. Our focus will be on appraise all the discoveries and near field and incremental exploration around our facilities and our future paths of production.
Claudio, if I may?
Thank you, Luca.
To complete the answer about tax rate.
The expected cash tax rate in 2016 will be in the range of 29%.
Now the last point about Versalis question. What we announced in 2014, in July, when we had this Eni strategy in London, was that we want to be more upstream and oil and gas. Versalis was one of our main staple or milestone to become more upstream. Immediately, also before, Versalis did very well because they transformed their business model. We invested money, but after 20 years, we succeed for the first time last year to become positive in Eni, in cash.
With our still free cash flow, which we are still investing.
We are happy about Versalis. It's a very good product. It's not now in our strategic view for the company we want. We are discussing now to find somebody that is helping us to make these investments. We are going to reduce our share, Eni share, and we are under negotiation, as you know. I can't disclose more because it's a commercial negotiation. I cannot disclose also what is the percentage of Versalis inside the EUR 7 billion. I hope that we are going to disclose very soon. [Proceed Irene], sorry. Irene?
Thank you. Irene Himona, Société Générale. I have three questions, actually. Firstly, you have lowered the oil price you assume in your four-year plan. You are targeting 3% a year production growth. Can you quantify the positive PFC effect in that 3% from the lower price? Secondly, you show a remarkable reduction in your new project for cash break even, I think it is slide 14, from $45 to $27. Can you say what the implied IRR is in that? The final question, going back to the asset disposals, the $7 billion target, can you talk about retail gas and exploration in that?
Yeah
How can we think about these two assets, let's say? Thank you.
Massimo will talk about PFC content and the kind of rate of return. I am going to talk about the rest.
Okay. The positive effect on production, more or less, Irene is 1,500 BOE.
Irene is 400.
Yes, per dollar. In terms of internal return in our portfolio, is in the range of 15% without Kashagan. If you take Kashagan out, the average is 15%. As far as, I leave the floor to Claudio, the disposal, in the number I've shown, Retail Gas & Power is not included, as we are not including that number any further disposition of Saipem shares. The decisions we take about the numbers not quantifying the EUR 7 billion, I leave the floor to Claudio to comment about retail.
Just a few words about Retail Gas, that with Versalis, and has been one of the items that we mentioned in 2014, because it's not a typical business, the Retail Gas, typical business of an oil and gas integrated company. Where we are? We are trying to get the maximum value before thinking about any other step. It's not in our plan. We have enough disposals in terms of we already got a lot, because in one year we did practically 90% of what we wanted to do in four years. We have additional disposal, on which we are negotiating, actually. We are now, I hope, far to conclude on some of them. Retail Gas is something that we can improve the value. We can improve the value and also the impact on our Italian market and returns. We want to wait, try to maximize it.
There is no short-term thoughts on it at the moment.
Thank you very much. Oswald Clint at Sanford C. Bernstein. I wanted to ask a question about the EUR 3.5 billion cost reduction through the plan. You pointed to the areas where you expect that to happen within the upstream. Can you say, is that based on early conversations or is that your aspirations there? And how quickly could you expect to get that number? And actually, if you do get it quickly, are you starting to think about locking in contracts at that price point for the next three, four years, kind of lump sum turnkey? You mentioned it with LNG, but is that something you're starting to think about much more broadly? And then secondly, maybe just with Angola, you have quite a bit of production projects in that area. Maybe you could just tell us if you're seeing any fiscal improvement from that country, please. Thank you.
Okay. First of all, the EUR 3.5 billion is not just an aspiration now. It's something that we already got in our plan, talking some [high-grading] and some contract, longer items, and our fleet in term of drilling rigs. So when we talk about this EUR 18 billion reduction, that goal that for which we got in a cost reduction of 39% and EUR 2.5 is on that we got on a 2,000 contract and then additional 1,600 contract, is something that we have our hand on. And as I said before, for the answer at the very beginning on the LNG, we are working a lot on that. We are working positively with the contractors. And I think that it's really a good moment.
I think that now we are really close to the minimum oil price, or we got behind that. So I think that we still have a window maybe of one year where you can really progress very positively in term of future margin. And that's what we are doing. We are very happy. Honestly, that was part of the initial strategy because we start doing that in May, June 2014, when the price was $110. We restructured completely our supply chain, organization, and also the contract strategy. So remember, we talked in the past about the different kind of EPC contract where we are now running and we are the position of main contractor.
We didn't want any more a contractor there running different contractor with different package. We are the main contractor. And what we are doing in Gabon, sorry, in Congo, in Angola, with the Block 15/06, and now in Egypt, the different fields, this kind of strategy. We are interfacing all the different packages, and that make a huge amount of savings and help us to have a direct contact with the contractors, and that is continuing. That is a very good period to do that. I didn't understand the last question. I was talking about the situation, the political situation in Angola, just checking your point of view on that. Maybe Roberto can talk about our projects. So the West Hub finalization and the East Hub that again end.
Both projects in Angola are going very well. Actually, a couple of days ago, we had the record of production in the West Hub with 94,000 barrels a day, which is almost the top of the FPSO capacity. We continue with a very short cycle time to put other fields into production in the West Hub. Meanwhile, the East Hub is progressing. We have drilled all the wells, and FPSO works are very well advanced. As you have seen earlier, we definitely confirm the first oil, second quarter of 2017.
Thank you. Theepan Jothilingam from Nomura .
Can't hear you, sorry.
Apologies. Theepan from Nomura . A number of questions, please. Firstly, could you just give us an update on Venezuela, your exposure there, both in terms of sort of cash flow and capital employed? Secondly, sort of linked to the question, Claudio, I guess, one of the challenges or opportunities for Eni is the mix in the portfolio between non-OECD and OECD. I think we've talked about it in the past. I guess, in some ways you continue to sort of have great success with the drill bit, but that puts you more biased to sort of non-OECD. I'm just wondering how you think about that in terms of your strategic outlook. Related to that question, just on your financial metrics, is there a level of gearing that you'd be uncomfortable to sort of move beyond? Thank you.
Can you repeat that? Sorry.
Yeah, sorry. Just in terms of the financial framework, I think you've given us a lot of numbers today, and that's great, but I wanted to know about gearing. What's your sort of threshold in terms of peak gearing? Thank you.
Okay. I'll talk about the first question, then the OECD and the non-OECD, and Massimo will talk about the rest. First of all, Venezuela is one of the country where we reduce our investment, especially the onshore, on the Orinoco Belt and the refinery. We progress very positively on Perla. Perla is doing very well, now producing about 500 million SCF a day. We signed a very positive agreement with the government, with PDVSA, also for the local market and also for the exports. We don't have outstanding. We don't have outstanding payments in Venezuela. That is, we don't have outstanding on the past pay, we don't have outstanding on the present. I think we cover our position very positively for the future. Now we are producing 500 million SCF.
We have to reach 800 SCF per day in the second phase, then we have to reach 1.2 billion SCF. They are looking for gas. They are looking for gas, not only Venezuela, but also Colombia. It's a market that became a regional market, that they import, they pay more. That is a relatively cheap gas for them. It's good for us because in any case, it's a cheap upstream. We have a good margin with the securitization. Venezuela, from that point of view, so far, so good, is clear that for the moment, we are standing by on the more expensive project. The second question of the discussion between OECD and non-OECD. I think now the boundary is more volatile than before. I think that it's not so easy to identify OECD, non-OECD. Risky, not risky.
The last couple of years, America is a very good country. We like a lot. We are there. We are producing more than 100 as well, equity production, but each company lost money there. It's a super OECD country. I think that we have to balance all the different risks, and we have to balance all the different risks and different costs. When you have cost of between EUR 12 and EUR 18 a barrel operating cost, you have to shut down your production, or there is a risk. It's not a geopolitical risk. That is an adverse business risk if you want to continue to have a cash flow. This year, we are going to have EUR 6.4 per barrel operating cost. When we show the little barrel with our technical cost and our breakeven, that is a mixture of different kind of countries.
It's clear, if you don't have EUR 20 technical, technically, EUR 20 per barrel technical cost, and EUR 27 average breakeven per barrel. You cannot cope. You are not in the position to manage a price, because prices could be high, could be low. You have to run your company and be ready for each kind of price. That is the risk, because we saw what happened in the last two years. We had six good years, but remember that the high price is an anomaly, not the low price. We had low price for 30 years and high price for six years, and now everybody's surprised we have low price. We live with low price. We have to be ready to live with low price, and our company had to take into consideration this kind of risk.
I think that the picture between OECD, non-OECD , the risk and not risky, we have to be able to have low cost. We have to be able to live with a low price, creating value. That's what we want to do, and that's what we achieved.
I give you just one number that is 0.3, but in term of leverage. We are not talking about gearing. That's our ceiling in our debt structure all along the four-year plan.
Hello. It's Mark Rapson, Morgan Stanley. I must say, I appreciate that you're keeping the slides relatively the same for last year versus this year, which makes it quite easy to see what's going on. Along those lines, I wanted to ask you about two things. If I look at the downstream guidance for last year, adding up R&M and chemicals, it added up to a figure of EUR 1.9 billion of CFFO over the four-year plan. That number seems to have increased a lot to EUR 2.9 billion now in terms of CFFO over the new four-year plan. I wanted to ask if there are any unexpected positives in the downstream restructuring, and basically what bridges that increase?
Along similar lines, the cash flow chart, which I think is now on page 19, shows that at a $63 oil price in 2018/2019, you expect to generate about EUR 12 billion of CFFO. Last year at that same oil price, it's not so easy to read off the charts, but it looked like that number was closer to EUR 15 billion. At the same time, it's at the same oil price and the cost of generating supplies from the positive side, why do you expect lower operating cash flow by the end of the decade?
If you talk about downstream, then you go with the rest. The downstream is quite faster. We got some changing in the downstream, that is true. There is the scenario that is better because our oil scenario is lower, and that accounts for maybe 65%. The rest is something that changed in our operations. Remember that we said we wanted to reduce capacity, 50% capacity. Now we say with 33% reduction, we are okay because we changed something in some of our refineries. Now, we are quite sure that we can reduce the breakeven of these refineries. We got some structural improvements. If you look at, you compare the two, you can think that 65% is linked to the scenario that is better because the oil now is lower. The 35% is better achievement in term of operating model.
Commenting on the cash flow growth, yes, you're right that we said EUR 15 billion during last quarter presentation, but you remember we had a long term oil price at $90. Now we are projecting the number at $65 in 2019. 65. We have 65 today. Just to explain, I said that the increase from the 80 to the 12, first two years versus the last two years. Around 30% is scenario, from $45 to $63, and the remaining 17%, that amount represents EUR 1.4 billion, is the industrial growth. Inside this industrial growth, EUR 1.4, more or less half is E&P because of the production growth mainly. The remaining part is equally splayed between Refining & Marketing and Gas & Power.
Around EUR 300, EUR 400, this is exactly, I would say, the one year additional contribution because you are right, last time we promised a cash flow from operations from these two businesses much lower. The increase more or less is EUR 1 billion in each of two, so on four years. Divided the four is around EUR 250, EUR 300 per year. That's the composition of the cash flow increase in 2019. Jon?
Thank you. It's Jon Rigby from UBS. Can I ask, bit of a shopping list, I'm afraid. The first is on the Zohr chart that you show, because I understood it when you first talked about Zohr, you talked a lot about the integration with the existing infrastructure that you have. Are you now showing, actually, I think a new pipeline to shore and a new gas processing plant and so on. Has there been a change of scope or is that just to do with the expanded full field development? Can you just talk a little bit about that? The second is, in all the company presentations over the last year or so, I think one of the tricks that has been pulled is that, of course, CapEx production outlook don't match.
Most of what you're spending over a two, three, four-year period is to do with projects that are going to come on beyond that period. I just wondered, could you talk a little about the sort of 2018, 2019 spend, and what you're assuming in terms of what you sanctioned in there? I know you talked about Mozambique and the onshore, but if there's any other mega projects in there, I'm thinking about Kazakhstan, potentially, I think. Lastly, just to pick up on something that Theepan mentioned is, I take the point about 30% and that being your ceiling, but the nature of the business is changing as well. You're becoming very much more upstream oriented. You don't have the reliable cash flows that you did have three, four, five years ago because you restructured.
Over time, is there a thought that actually, although 30% is a nominal level you talk about, your expectation would be you would run a slightly lower gear balance sheet than that in mid-cycle conditions? Thank you.
Just to comment about that. Yes, your market is correct. We changed it a bit, the scope of work. First of all, for the volume, because we tried to accelerate our production. We wanted to, the gap between the first and the second phase, or the accelerated phase up as closer, because we start 2017, 2019. That means that we don't have enough capacity onshore and in the pipeline to accommodate practically 3 billion SCF a day. We need additional two plants, and for that reason, we already started the civil work. We got the land, and we also have the contracts already done. That is one of the main things. We are still evaluating because we have some platforms. The pipeline is one point, but we have the umbilicals. Through the umbilicals, you run all your subsea ahead, all your wells.
Now we are, in this case, we put some different scenario because we are evaluating the cost to restructuring an existing platform to do the remote control with umbilicals or build a new platform from scratch. As we said before, because that is a window of opportunity where we have a fast track platform construction and the costs are low, we are really seeing, and the slide is showing that it is faster and less costly to add a new one. That are the two main reasons. The other question was?
Jon?
Oh, yes.
As far as the leverage, Jon, I said that 0.3 is our ceiling. That's the maximum we can think about in projecting these numbers. Our assumption is to stay below 0.3. Definitely, what we have to do is to manage this mainly the first two years, which we are assuming, I would say, a low oil price. We have to manage, I would say, the short term and the medium term, a different point of view that Claudio explained very well in his own presentation. That's the trick. Definitely our intention is to remain quite low. I would like to remember that we are starting this year from a 0.21 in term of leverage.
I didn't answer about the FID. Sorry. In the plan, we have 12 FIDs, and we address two into this year, Zohr and the next one will be Coral. We have a series of FIDs, and we have in Kazakhstan, in Karachaganak, and also in Kashagan. We have FIDs, the first FIDs for us is in Mozambique, will be onshore, the two trains, but we have still additional two floating LNG. There we have a long phases. We are fine-tuning the LNG development also with the market. The market will be quite short in 2023, 2024. We are also starting there, but we have at least one additional LNG, at least the two trains in the Coral. We have Nigeria, we have Italy. What, sorry? Yeah, Congo. Sorry.
Congo, we have the phase 2, the phase 3 and, hopefully, also the phase 4. Always for the name, because we discovered more than 6 billion barrels of oil in place. We are just as for Coral, trying to set up. Our aim is to reduce our inactive capital. The investment that we have in the four-year plan that are not related to production in the four-year plan. That is a huge, really a big target for us. We want to be faster. Now we have about 32% enough capital, one, because of Kashagan oil, and we hope to reach a 7% by the end of the plan. We want to remain in a maximum 10% of inactive capital in the plan. We go gradually phasing the project and try to attack what we can put in production as soon as possible.
We want to have an upfront cash flow that is able to give enough capital to invest without ever touching the reserves in terms of gearing and leverage.
To complete what Claudio said about the inactive capital employed, the work in progress we have in our invested capital, the amount is around 30% at the end of 2015. It is expected to drop at 12% at 2019 because of the startup of Kashagan, Goliat, Jangkrik, and other projects that will go to startup all along the four-year plan.
Thank you. The first question is on the new project, breakeven, which is very impressive. It made you at $27 per barrel. My question is, by excluding Zohr, could you please give an idea of this level? The second one is on Libya. My question is, what's the role Libya is going to play in Eni's strategy in the coming years? When I compared this business plan with the previous one, I noticed that the contribution of Libya is lower, and this gives the idea of your flexibility on the one end, but on the other end, it probably testifies something that might worry investors. The third one is, how far do you see the chance to start or restart the buyback program, if you see it? Thank you.
For the breakeven, I don't know if you have any idea without.
We are checking.
Okay. I start talking about Libya. We give you the figure about the breakeven without Zohr. For Libya, clearly Libya is still a core country for us. We are not investing like before. We are reducing our investment, and overall, in the four-year plan, we have in the last two years an average production of about 250,000 barrel per day, but remains very crucial. We are working. So far our production is still in line with the production we presented before. Fortunately, now we are in a much better position in terms of flexibility. We have a lot of resources. We said that in the first phase, we had 200,000 barrel per day from Zohr. We are going to reach 400,000 barrel per day. Egypt is going to give 500,000, 600,000 barrel per day, but we have also other countries. Libya is still important.
At the moment, waiting a better situation. We reduced our investment also if we have been active in exploration because we made a discovery last year in Libya, and we are developing offshore Bahr Essalam, second phase, that is going to give an offshore contribution. Libya has a huge potential. In potential about reserves that we already discovered. As we said, we can double our gas production there and condensate, can double. We are ready also in terms of progress. Libya is important. We are there. Now we are moving around on all the big discovery we made. Clearly, it's still a strategic country for us.
As far as the breakeven, so the breakeven of the portfolio without Zohr would be $34 per barrel, from 27 to 34. I don't know, do you want to give an answer about the buyback?
No, I was going to say that what is inside is not outside.
Yeah.
Not just to tell. We discover it's there. You can remove everything but
Do you want to talk about the buyback?
No, I think that if somebody has to talk about the buyback, it's you. Thank you very much. I can't talk about everything.
You know that buyback is, by definition, the more flexible tool. We will leave any decision about this flexibility looking at the cash neutrality and the breakeven that we projected with this four-year plan.
Thank you.
Alessandro Pozzi from Mediobanca . I have one question on exploration. Your track record has been very good since 2008, also helped by giant gas discoveries. I was wondering how you think about exploring gas versus oil in the current environment? When it comes to competitive edge on exploration, what do you think your competitive edge is versus your competitors?
The first question is what about exploring more gas than oil? If you see in our forecast, the gas is much more than oil. You see we have a ratio of, I think that is written in the slide, but it's one third oil and third gas. Honestly, when you explore, you don't say, "I want gas," it's not in a supermarket. You go there, and you want hydrocarbon. We are being in new play with more gas there, and we think that gas will be the future, honestly. We think in the long term, our position is the long, long term will be really gas and renewable. In the long, long term, after 2050. We think that the gas we discover is in the right position because it's high and it's in the Mediterranean Sea, and we have additional discoveries.
We don't mind to find also oil, and we find a lot of oil in West Africa because all the main discovering in West Africa, we have standards, but it's mainly Congo and Angola oil. Around Angola, we still have a lot of structure because we never talk about that, for example, that is oil, that will be ready to be linked to Angola in the future to continue to have the plateau. That is our exploration. The second question was about the advantage?
Competitive advantage on exploration.
Sorry?
Your competitive edge.
Our competitive edge in exploration is Eni. That is our competitive edge because we have, I think, the best explorer, the best strategy, and the best result. You must be very lucky, but if you are lucky for seven or eight years and you discover five super giants, and you see we discovered 2.4 times what we produce in the period against the other that discovered 0.3. Because we decide to be focused on exploration during the period where everybody bought reserves because they thought they were cheaper. We thought that is not true. When you discover, you discover a $1.5, $1, last year $0.70. You cannot buy anything now. Also, now you have to spend at least $5, $6 per barrel, up to 10 also now. We thought that we had to be full.
When you are focused, you create your tool, your property tool, your people. You motivate your people. You centralize. Before, we are not centralized. You say, "We have to do that," and we start it. If you want to do something, especially in an area where we are just the medium exploration company. We had a very big area with a lot of space. A lot of space. You start with a big regional model, and you tell your people, "You are important. You have to be." That create a culture of exploration. For that reason, my answer is our upside in exploration is Eni, is us.
Thank you.
Lydia?
Thanks. Good afternoon. It's Lydia from Barclays. Just these three questions if I could. The first one, just a definitional thing. On slide 13 on the CapEx numbers, talk about upstream of EUR 37 billion and then group net CapEx, net of disposals of EUR 37 billion. What adjustments are you making with disposals? Should I be adding back the EUR 7 billion, so your group CapEx over the period would be EUR 44 billion? Are you just adjusting for the CapEx you would have spent on those disposals? The second one was coming back to the disposal slide, and thank you for the detail on that one. If I look at the numbers or the value you got from NAM, from Galp, and from others, it was about EUR 1 billion less than you might have hoped to get in the plan last year.
How are you thinking about the timing of the disposal and whether you're really maximizing the value you're getting? Just another numbers one. Are you able to give the cash flow per barrel of the new production, either on an absolute basis or relative to the base production? Thank you.
Okay. So?
I don't have immediately available the cash flow coming from new production. I will let you know. As far as the CapEx reconciliation, yes. We're talking about EUR 37 billion as far as upstream before disposals, and EUR 37 billion at the group level after disposal. Means that the amount that should be linked to the disposition, we are projecting the EUR 7 billion, is the CapEx part, will be substantially offset by the investment in business other than upstream. We are talking about EUR 3.5 billion, more or less, plus and minus. Your third question was about the difference in disposals. No. I would say as far as Galp and NAM, the amount is exactly the same. It's just a matter of timing because the NAM disposition has been completed in January 2016. What is missed versus the previous plan is EUR 300 million.
That is accounting the EUR 7 billion we are announcing for 2016, 2019.
Thank you. It's Brendan Warn from BMO Capital Markets. Just following on from that question from Lydia in terms of slide 13, just to clarify or just to split out some numbers. If I can link it to your growth target out to 2019. Just in terms of your development or staying business CapEx and your assumed decline rates, so you spend on your base business as part of that EUR 37 billion. Just if I can understand in terms of pre-FID projects such as Coral, is any CapEx assumed in that EUR 37 billion for future? You sound like you're putting 100% probability that you're going to go to FID at Coral, but what sort of additional CapEx will we be looking at in the 2017 to 2019 period?
Yes, for me to turn on Coral. In these four year plans, we have Coral CapEx. How much? The way the book is big overall is EUR 5.3 billion over the plan, if I remember well, equity investment. That is covering Coral, that is also covering the pre-FID cost for number. That is a figure that we have not completed, but what I have in mind is EUR 5.3. Egypt is the number 1 country, term of investment. We have Italy, then we have Mozambique, then we have Congo, that are our country we are going to invest, but they are in sight. The maintenance CapEx is around EUR 2 billion per year. Maintenance in term of production enhancement, the production optimization and.
Massimo Bonisoli from Equita. Just two questions, just on the appendix. The first is regarding gas. You showed the assumption on gas prices in both U.S. and Europe. Does it make sense to share with us some sensitivity on gas prices, considering the fact that in Europe, maybe they are decoupling versus the oil price? The second question is regarding the number on Zohr. The peak production in the appendix is about 200,000 barrel per day, and you stated it's 500.
First phase, EUR 200, 2017. Second phase, EUR 219 addition. You reach overall EUR 400 our equity.
Okay, it's not at the end of the period, it's EUR 400.
No. As far as gas, I guess that Umberto has the best sensitivity.
In terms of expected price of gas in Europe, I would like to look at that first from which is more important from our business point of view. As already presented in our plan, our main target is to keep our cost of supply progressively more and more linked to the market of destination, to the price of market of destination. We look more at the differential than the absolute. We look more at our ability to regain margin by the end of the period on all our supply gas. Certainly, for us, this is the biggest challenge, to complete our process of supply renegotiation, together with the other aspect of cost of gas, that is the cost of transportation, for which we have already achieved some saving in 2015, and we have clear target to complete by the end of the plan.
If you look more at the dynamic of gas in Europe, certainly, it's difficult to predict the balance between demand and supply in Europe the next 4 years. Easy to imagine that we will continue to have substantial oversupply, particularly because recovery of economy seems to be lower than expected, considering the fact that we are not seeing a rapid implementation of the emission control measures as they have been announced in the past year. The biggest upside will be certainly an increase in cost of CO2 emission. That will be a major swing in the mid-term for the balance between offer and demand, and therefore price. The power sector today basically is not playing yet a sufficient role in increasing gas demand. We compete with renewables, but basically, we compete with coal.
Good afternoon, Giuseppe Rebuzzini , Fidentiis Equities . First question is again about the breakeven price for a new project. You've given us the breakdown between onshore, offshore, and shallow waters. Can you give us also the breakdown between gas and oil? Second question is about the gas and power. In the context of the EUR 2.8 billion CFFO throughout the plan, is there any residual cash flow from make-up gas related to your take-or-pay agreements within that figure, and what is that number? Third question is a follow-up about Libya. In particular, if I'm not mistaken, the Wafa compression project has disappeared from the plan. I was wondering why that happened. Last is about the oil downstream. If I look at your slide, it seems that you have completed the restructuring and you're happy with the current structure.
Does this mean that you exclude any further disposals on that area, particularly outside of Italy? Thanks.
Doesn't follow. Okay. The first is about the breakeven. Cannot say exactly it is a gas breakeven or it is a oil breakeven, because it is also a mixture, because there are lots of gas that is associated gas. We are going to say that we are associated to the gas production. What we can see that our breakeven is coming, for example, from Congo or Egypt. Egypt is not just Zohr, it's also Hapy and Umm Sidom discoveries that are producing now. Their breakeven, they are very low. They are creating value in our whole package. Also when you look at Angola LNG, that is a mainly oil field, some associated gas, is at a given that is just a little above the $27 per barrel. It's in the range of $30-$32. What we can say that gas is normally cheaper.
In term of treatment, in term of repressurizing all the system, and line, and so is a little bit cheaper. Our gas is absolutely the cheapest because also the volume are big. That is the answer. That there is now a very low gas and a very high oil. We don't have discovery in the last seven years, expensive projects in term of oil, a very complex one. Goliat is the highest we have now, is below 50. That is in production. Just to give you information, Goliat that started less than one year ago, today is producing 90,000 barrel per day. In four or five days, is practically reaching the full production. Full production, remember, is 100,000 barrel per day.
Make up gas
Libya, just I talked about the disappeared field. Wafa is not disappeared. It's still there. We didn't mention Wafa now because Wafa in the south, is in the south of the desert, at the moment, we consider that is safer to work offshore and without developing any onshore field. It's there. We have R&M. We have also R&M on disposal, if I remember well, is the last questions. At the moment, we are not thinking. We are still some assets outside Italy. Outside Italy, we have refining, and we are getting good profits from that refining. They are in Germany, but we have also the retail in Germany and France. Where we have refineries with a strong retailing network, we are along the chain of the value. Before selling, we have to think about.
I don't want to exclude. At the moment, it's not in our program. We had a question on Gas & Power.
Make up gas. The remaining make up gas, beginning of this year, amounts to EUR 400 million. It will be cashing in along the four-year plan.
Perfect.
Alastair Syme from Citi. Can I just come back to Mozambique and Coral? Can you give an indication of what the technical barriers are for this project and how comfortable you are with the technology, with the execution? You mentioned the CapEx number. I appreciate that's all of Mozambique, but sounds a pretty big number if you gross it up in terms of overall CapEx for Coral.
Roberto can answer about how much we believe technically in Coral.
Sorry. Okay. No, about Coral development. Well, it's basically a few wells, sub sea wells, as Claudio said earlier, and a floating LNG. We spent a lot of time in engineering the floating LNG. You have to consider that the gas in Coral is basically pure methane. From the process point of view, it's not as complex as other floating LNG with a significant content of liquids and pollutants. Process-wise, it's simple. Also in terms of storage facilities, well, LNG carriers are everywhere in the world. The combination of both made this project definitely a viable project from a technical point of view. This has been proven also by the fact that the three major consortia who bidded for the contract, actually, they increased the production capacity from 2.5 up to around 3.4 million tpa.
In terms of cost, again, as Claudio told you earlier, it's really a very good time to launch projects because we were able to achieve impressive cost savings on all the different components. To give you an idea, the floating LNG itself, as a liquefaction capacity, is in a range of 1.3 billion mtpa, which is comparable with many onshore projects. This has been possible, again, thanks to the engineering effort from one side and the tendering effort on the other side. Don't know whether I answered your question. Okay.
Okay. Now?
Thank you. It's Neill Morton from Investec. Two questions, please. I noticed recently that Statoil moved to introduce a scrip dividend, they, like you, have a large government stake. I appreciate that equity analysts tend not to like scrip dividends, I just wondered, in a depressed oil price environment, why you would choose not to have that as part of your financial toolbox? Secondly, on Zohr. This is maybe a question for this time next year, perhaps talk about follow-on exploration, either in the same license or in the neighboring blocks, and whether the increased focus or the acceleration of the Zohr development actually makes you less likely to drill these prospects quickly. Thank you.
Just a few thoughts about scrip and other kind of elaborating tools on our financial statement. I think that we decided last year to reduce our dividend because we wanted to be very clear, very linear, very readable by our investors. Scrips or hybrids, we're going to do something that then you have to go back with the buyback. You enter in a kind of contract with your investors, the situation is now clear. We want to be simple, simplicity our financial attitude. That is what I think, maybe not so technically as Massimo can say, I don't want complication in my life between me and my investors. I think that was clear. You want to-
On top of this. That definitely is enough. I would like just to say that we are paying fully cash, because we can do it. This is tested in our financial situation. The overall situation, including investment and the 0.3 ceiling in our leverage, means that it is compatible. Definitely, what we are doing, we are retaining some extra flexibility on top of this. Definitely the 40% uncommitted CapEx I mentioned is one of them. Second, I just mentioned that in the EUR 7 billion dispositions, there are some potential projects that are fully in line with our strategy, so we don't have to divert versus the strategy that's been set. That could be added in case of need. We mentioned we take Gas & Power. We mentioned additional share of Saipem.
I would say, we are not mentioning in this list some extra financial lever of flexibility, such as a scrip or an hybrid. That is something that the others have already done in respect of which we are retaining some more flexibility in responding to our commitments.
I was going to ask to answer about balance between developing Zohr and reduce our activity in the area. What we are going to do this year is not just developing Zohr. We are going also to drill an additional exploratory well in Zohr, in the area. It's clear that when you discover so much gas and you put investment, you have to fast recover this investment because you have to create a value and create margin what you are doing. I think as investor, it's the first things you are asking me. Because we are growing, and underneath we have another possible play, we are going to run in parallel. We are going to drill one of these while we are going deeper and see if there is an additional potential, and then we see what we can do.
That is inside our strategy.
Okay, the last question. Second one before the first. The first of the last.
Thank you. Thomas Adolff from Credit Suisse. Can you hear me? Just around capital allocation, the question goes back to Mozambique. We talked about the short-term cash cycle and returns and how LNG fits into that. I wondered, investing in Mozambique Mamba LNG at 50% equity, it's quite a big exposure as far as CapEx is concerned. My question is, would you take FID at 50%, or would you wait until you reduce the equity? Is that part of the market already presented today? As far as Zohr is concerned, the second question, is your base case post-government backing rights, so you have 50% as opposed to 100%? Thank you.
No, to the first question, I think that in Mozambique, 50% is too much. I think the same. That we are working on that, we are progressing quite well. For Mozambique, for Zohr, we have 100% of the second party at the moment. I think also in this case, to have 100% of a huge amount of that with additional potential is too much also in this case. That is, that are the two possible first aspects that we got to consider for disposal.
Okay. Thank you very much.
Thank you very much.