Good morning, and welcome to Eni's strategy presentation. Today, agenda is divided in two parts. In the first part, Massimo and I will give you an outlook on our four-year plan. In the afternoon, Eni's top management will give more details on the business plan. In the first part of this morning, of this presentation, we will describe how we transformed our company to make it structurally resilient at a lower scenario. We move to our four-year plan. After this, we will give more space to our sustainability plan and decarbonization strategy. Finally, Massimo will describe the financial plan and the distribution policy. Let's start with a look at the structural changes we implemented in the past few years that are the foundations and the drivers of our future.
Immediately after my appointment in May 2014, and before the price collapsed, we made a decision to change certain fundamental elements of our business and corporate structure. Firstly, we transformed Eni into a simpler, more compact organization, more concentrated on core businesses. Second, we increased our focus on exploration and changed our development model to fast-track our discoveries. Third, we restructured our mid and downstream businesses to reach positive results. Finally, we carry out a strong cost efficiency program in all our businesses and corporate functions, improving our underlying financial resilience. Through this action, in less than four years, we have set a company that now can grow in a lower scenario, enhancing the value for our shareholders. In upstream, we introduced two major innovative elements, the dual exploration model and our new approach to development. This has generated major results.
Since 2013, the dual exploration model has generated $10.3 billion of upfront organic cash flow. Moreover, our integrated development model allow us to value around 40% of the 4.4 billion barrels discovered over the last four years, generating an NPV of around $8.8 billion. The new development model accelerated time to market and increased control on execution through in-sourcing of new competencies, a fully integrated exploration, development, and production phases, changing our contractual strategy, and optimizing our supply chain. The last three years seen impressive results, and we have delivered most of our start-ups ahead of schedule and on budget. The four main projects of 2017 had an average time to market of 2.7 years, a record for deepwater and nearly three times faster than the industry average for similar projects.
Our integrated model of exploration and development has been a major element of success. We reached a record average production of 1,816,000 barrels per day last year while reducing our E&P CapEx by 40% versus 2014. As a result, our upstream CapEx cash neutrality fell to $45 per barrel, less than half the level of four year ago. While we were strengthening our E&P business, we almost completed a full turnaround of our mid downstream. Gas and power has already achieved an underlying positive result. We have progressed significantly on the renegotiation of long-term contracts and have almost fully recovered our take-or-pay. We continue to work on reducing logistic and operating costs.
On the other side, we set up a new platform for growth, a dedicated company for the retail gas and power business, Eni gas e luce, and a stronger integration between gas and power and upstream business to successfully develop international LNG. In refining and marketing, we enhance efficiency and optimization of our crude supply, halving refinery breakeven from $7.80 per barrel in 2013 to less than $4 today. Also, chemicals business has improved, beating its best performance ever over the last three consecutive years. Overall, the turnaround of these businesses has generated an aggregated increase in operating cash flow of EUR 12 billion in the past three years. To conclude this first section, I would like to emphasize our outstanding financial achievement.
In this period of low prices, we have not only increased upstream production and brought on stream more than 30 major projects. We have also succeeded in reducing our gearing to 18%, the lower end of our three-year group. Overall, thanks to structural cost and capital savings, upstream growth, and mid downstream turnaround, we halved our all-in cash neutrality from $114 to $57 per barrel. Considering the organic contribution of our dual exploration model, our cash neutrality was further lowered to $39 per barrel. Eni reactions were very effective. Starting before the price dropped, our strategy was not defensive based only on cutting costs. Rather, it was proactive, involving our organization, all the businesses, and all our industrial model. We emerged from this difficult period stronger, with all the tools to improve our performance and fit to grow even in low scenarios.
Now let's move to our 2018-2021 strategy presentation. Our three-year plan is based on the foundations and the drivers that successfully transform our company to grow in any scenario. Now we are moving towards the expansion of all our businesses based on two key levers, integration and efficiency. First, a deeper integration in terms of competencies, assets, processes, and businesses, and integration with our stakeholders. This enhances the synergies in our operations and unlocks all the value along the chain, reducing uncertainties in our upstream growth, as we did with Zohr, while increasing our equity LNG volumes, as was the case of Jangkrik in Indonesia, reinforcing our global downstream footprint, and implementing our distinctive renewable model. Secondly, efficiency. That means financial efficiency through a rigorous discipline, technological efficiency leveraging an increased digitalization, and finally, carbon efficiency with a strong action on the carbon footprint.
Now I will present how these concepts are translating into targets for the three-year plan. Let's start with the upstream. The Brent scenario for this plan is very similar to the one we adopted in the previous plan. In the upstream, our project will deliver an improved production growth of 3.5% per year versus the previous plan. Exploration will continue to provide fuel for future development, and we are targeting the discovery of two billion barrel of new resources. Upstream growth will continue to add new higher margin barrels. We expect the price we need to cover our CapEx to fall at around $40 per barrel, starting from 2018. Finally, we will generate around EUR 22 billion of accumulated free cash flow from the upstream at any scenario.
All these figures include the impact of the deal we announced this week, the entrance into Abu Dhabi upstream, and the disposal of 10% share in Zohr. Now some details on the deals closed on Sunday in Abu Dhabi. We were awarded a stake of 5% in Lower Zakum and 10% in Umm Shaif and Nasr, acquiring more than 300 million barrels of proved P1 reserves and 1 billion barrels of resources. Both concessions will last for 40 years with a rising production profile. In Lower Zakum, ADNOC is targeting production growth from 400,000 barrels per day to 450,000 barrels per day. In Umm Shaif and Nasr fields, production will more than double from the current level of 300,000 barrels per day. This is a major milestone to enhance our positioning in the Middle East, further diversifying our portfolio in a country with a great potential.
At the same time, we also sold a 10% stake of Zohr to Mubadala, bringing a new strong financial partner for Zohr development. The net cash effect of this transaction is positive, this further demonstrates the value of our dual exploration model. Overall, as a result, these initiatives and Zohr dilution, Eni's production will benefit from an additional long-term contribution starting from 2018 with a material upside potential. For exploration, we are entering now in a new phase of our strategy. During the downturn, not only we succeeded in finding 4.4 billion barrels, but we have also been able to increase, in an impressive way, our exploration net acreage, which now stands at 400,000 sq km, almost 3 times the level of 2013. We are now ready to start a new cycle of the exploration campaign.
Our undrilled exploration portfolio today stands at a total of 10 billion barrels of net risked resources, has a vast range of exploration opportunities, which provide us with a high level of flexibility in selecting the best prospects. Our strategy is still focused on conventional plays, mainly concentrated in offshore Mexico, West and East Africa, the East Mediterranean Sea, the Middle East, and Far East. We are already familiar with most of these basins in terms of geology, contractual structure, operation, and fiscal terms. We will continue to target large exploration prospects with a short time to market, low development operating costs, and high cash flow generation. During the 4-year plan, we will spend around EUR 900 million per year, targeting about 2 billion barrels of new equity resources, at about $2 per barrel, drilling 115 wells in more than 25 countries. We are exploring with high equity stakes in order to continue to fuel our newer exploration model.
Now production. New project start-ups and ramp-ups will account for around 700,000 barrels per day by 2021. Including also, adding, 200,000 barrels per day of production optimization, we will deliver a production growth of 3.5% per year up to 2021. In 2018, we have raised our original guidance after the conclusion of Abu Dhabi deals to 4%, including the effect of 10% of Zohr disposal. All our growth will come from projects that are already sanctioned or that will reach FID this year. We will deliver 15 major start-ups, and will operate around 80% of our production. In terms of geographical split, the contribution of North Africa will drop from 39% in 2017 to 33% in 2021, to the advantage mainly of Asia Pacific and Middle East, whose contribution grows to 12%.
Our asset base allow us to target an annual average growth rate higher than 3% in production also for the longer term, to more than 2.3 million barrels per day in 2025. Now some of our key projects. They are mostly giant fields with long life, high plateau, and which drive a shift in our underlying upstream cash flows. Even more remarkable is that most of these projects come from our exploration performed in the last five years. Thanks to our integrated model of development, they started or will start up production with a very competitive time to market. These projects will contribute around 400,000 barrels per day of equity production at the end of the plan, out of more than 700,000 barrels per day of all the main ongoing projects. More detail will be delivered by our senior management this afternoon.
In addition to driving growth, our projects will continue to push the value of our overall portfolio significantly higher. 2017 start-ups have increased the value of legacy barrels by $3 per barrel. Looking forward, our new projects have a breakeven of less than $30 per barrel. They will generate a material incremental value reaching more than $25 per barrel by the end of the plan, at a flat Brent price of $60. This effect, together with the legacy asset contribution, will deliver a cash flow of $18 per barrel. This will grow to $22 per barrel in the case of a $70 Brent. Upstream cash flow will continue to grow. In 2018, it will be above EUR 10 billion, up 10% from last year at the same scenario.
By the end of the plan, this will continue to grow to more than EUR 11.5 billion at $60 Brent, with an upside to EUR 13.6 billion at $70. Upstream free cash flow will more than cover our dividend during the plan period, even at $60 scenario. Coming to our mid downstream, here is a quick overview of our key business targets. The figures here presented are the sum of gas and power, R&M, and chemicals. We expect operating income from our mid downstream to grow to EUR 2 billion at the end of the plan and generate an aggregated free cash flow of around EUR 4.7 billion. In detail, our gas and power will grow on the base of the following actions.
Focusing on equity gas and energy marketing, leveraging integration with the upstream with equity gas, improving profitability of our European gas portfolio, and adding value to Eni gas e luce retail business by growing the customer base in our core countries by 25% to 11 million, and expanding extra commodity services, leveraging on digitalization and analytics. These actions will allow us to remain structurally positive in the future. We will grow EBIT from EUR 300 million per year in 2018 to around EUR 800 million at the end of the period, and of which 60% comes from the retail. The accumulated free cash flow from gas and power will be EUR 2.4 billion during the plan. LNG will play a crucial role in creating a stronger gas and power. Looking at the future, we have a positive vision on the evolution of the gas market.
In the last three years, gas consumption in Europe increased by about 70 BCM, recovering about 60% of the major loss between 2008 and 2014. Asia confirmed the growing trend of the last decade, driven mainly by China, that in 2017 increased its gas consumption by around 15%, supported by ambitious target for gas in the energy mix. There will be needs for new LNG projects, and this will present major opportunities for our gas assets. We are accelerating the ramp-up of our LNG portfolio, and now we expect to reach 12 MTPA of contractual volumes in 2021. Out of which, 8 MTPA from equity production, mainly from Africa and the Far East. This way, we will capture market opportunities through the flexibility of our upstream portfolio.
LNG volumes will further increase to 14 MTPA by 2025, an improvement versus the 10 MTPA of the last plan, putting us amongst the top players in the market. In refining and marketing, we will see strong EBIT growth to around EUR 900 million by the end of the plan, based on a flat margin scenario of $5 per barrel. More importantly, over the plan, this business is expected to generate more than EUR 2 billion of free cash flow.
The main drivers for this result will be the optimization of our refinery process to maximize yield of middle distillate, the restart of our S- Plant in Sannazzaro, set for the end of this year, growth of our green capacity with the conversion of the Genoa refinery well underway and expected to be operational by year-end, and second phase of Venice to come on stream by 2021. In marketing, we plan to consolidate our leading position in Italy, targeting to maintain a market share of 25% while increasing our focus on wholesale. Importantly, we expect positive contribution from innovation and sustainable mobility initiatives, such as LNG and new products. Versalis, our chemicals business. In 2017, we delivered record results. The transformational plan allow us to make the most of the favorable market conditions. For the future, we consider a more conservative scenario.
Assuming tighter market conditions, we are targeting an EBIT around EUR 400 million at the end of the plan. In any case, an improvement versus last year's result, netting the 2017 scenario effect. To do this, we are moving along three guidelines. Enhancement of our European operations through integration and efficiency, while upgrading our portfolio with differentiated products. International development, strengthening our presence in Asia with LOTTE, and expanding our international commercial network, especially in Americas and the Far East. Bio-based chemistry, where we are developing new industrial platform for renewables and exploiting the market potential of these new intermediates. Renewables. An emerging reality that is becoming for us an industrial business, which thanks to integration with the existing assets and core activities, creates new business opportunities and add value. Our distinctive model consists in replacing internal gas consumption of our assets with solar or wind power.
This way, we leverage industrial, logistical, contractual, and commercial synergies to create extra value in our projects. This approach allows us to reduce energy costs for our facilities and makes more gas available for local consumption or export, increasing our unlevered average IRR of our solar and wind projects to around 10%. We are also developing a number of projects not related to our assets that deliver clean energy to the domestic grid in the countries where we operate. With already identified and ongoing projects, about 65 projects, we will add around 400 MW of new power capacity in the next couple of years. We will develop 1 GW of new capacity by 2021, investing EUR 1.2 billion, and up to 5 GW by 2025, mainly in the countries we operate in. Another key driver of our plan is digitalization and the continuous focus on innovation.
We are developing more than 150 projects that cover our entire value chain. For each physical asset, we are creating a digital twin that will enable us to predict and control our operations in advance in order to improve safety, performances, and reduce emissions. The core of our digital model is our Green Data Center, where today we can call on 22.4 petaFLOPS of computing capacity, one of the top 10 supercomputers in the world. Our first priorities are safety of our people and asset integrity. The widespread application of sensors, devices, and advanced algorithms will have a very strong impact on HSE, efficiency, time to market, and cost.
In particular, by the end of the plan, we will reach a 7% reduction on production cost, thanks to advanced algorithms to ensure the reduced asset downtime and higher production rates, and a predictive analytics system based on big data, which allow us to optimize maintenance, logistics, and well operation costs. A 30% decrease in non-productive time from 7.5%-5%, thanks to the implementation of advanced machine learning algorithms in all operated wells, and a 15% reduction in the exploration phase from asset acquisition to the end of the delineation activity. Let's have a look now at another key lever of our plan, the decarbonization strategy. Our path to decarbonization has four main drivers that concern both our core businesses and new energy perspectives. The first is to lower CO2 emissions in all our operations. Secondly, we will continue to expand our low cost and low carbon portfolio.
Third, we will keep on developing renewables. Finally, R&D will play a key role in our decarbonization strategy. On carbon footprint, we have already reduced our direct CO2 emission from upstream by 40% since 2007, improving all our performances and indices. By 2025, we target zero routine gas flaring and a reduction of our retained emission by 80% versus 2014 to reduce overall upstream unitary GHG emission by 43%. In the long term, we rely on the strength and resilience of our low-cost portfolio. With an average breakeven price of less than $30 per barrel, our projects will remain competitive under all carbon price scenarios. In addition, the increasing role played by natural gas in our portfolio will make it stronger. Eni applies a carbon price sensitivity of $40 per ton of CO2 in real terms that implies a strong readiness in all our projects for emission optimization.
Even under IEA Sustainable Development Scenario, our portfolio confirms its resilience with a reduction of internal rate of return just of around 0.8%. Our decarbonization strategy is also based on the development of green businesses. Overall, we are investing more than EUR 1.8 billion in these initiatives in the Four-Year Plan, including R&D. In the downstream, we are already producing by-products from our facilities. Thanks to our past patrons, we were the first to convert a traditional plant into a biorefinery in Venice, and we will complete the Gela conversion by year-end. Together, they will produce 1 million tons per year of green diesel by 2021, making Eni one of the top producers in Europe. We have also launched a series of green chemicals projects, such as intermediates from vegetable oil and the experimental guayule from crops to produce natural rubber.
Finally, as already said, we will grow our new energy business to 1 gigawatt by the end of the plan. Overall, total CO2 savings is around 28 million tons in the Four-Year Plan, which include direct and indirect emissions. Now I leave the floor to Massimo for the financials.
Thank you, Claudio. Good morning, all. In coming years, we will continue to focus our financial discipline and sustainable growth aimed at further strengthening our business portfolio as well as accelerating the generation of shareholder value. Financial discipline means CapEx selection, efficiency, and cost control. CapEx remains unchanged versus the previous plan, and we retain material degree of flexibility in case of a sudden shift in the scenario. As always, OpEx control remains central to our model. Sustainable growth is a consequence of our financial discipline combined with the quality of our portfolio, delivering not only production growth, but also reserve replacement, rising margins, and midstream, downstream expansion. These outcomes will be achieved through projects that are already well advanced, thereby de-risking the plan.
The reduction of our cash neutrality on one end, and the remarkable amount of cash to be captured in higher scenarios on the other, show how resilient, as well as cash generative our portfolio is. Shareholder return is our core value. It is the ultimate objective of our relentless financial discipline and sustainable growth, making our progressive remuneration policy now a reality. As I said, we have held our CapEx flat versus the previous plan at less than EUR 32 billion, while in 2018, we are reducing our CapEx guidance to EUR 7.7 billion to reflect the recent transaction in Abu Dhabi and Egypt and further optimizations. More than 80% of the planned CapEx is dedicated to upstream, with EUR 15.5 billion budgeted for our integrated development model, EUR 8.3 billion for production optimization and maintenance, and around EUR 2 billion for exploration drilling.
By the end of 2018, we will be FID-ing an additional five key projects that, together with the ongoing ramp-ups, will entirely underpin production growth by 2021. This further strengthens and de-risks our plan by locking in CapEx at the bottom of the cycle. We will also continue to invest in our R&M and chemicals with an aggregate expenditure of EUR 3.5 billion and an expected ongoing project IRR in the range of 10%. The same unlevered return is expected from our renewable projects, with CapEx in the range of EUR 1.2 billion over the next four years. This is almost double the previous plan, and we continue to identify new opportunities in line with our development model, the one that Claudio just described. We retain substantial flexibility with more than 50% of our CapEx uncommitted by the end of the plan.
Focusing on the upstream, around 65% of the overall new development CapEx is related to 14 main projects. Some of them has been commented already by Claudio, the most important one. These projects are expected to contribute 500,000 barrels of plateau production by 2021, becoming material drivers of net cash flow growth during the plan period and beyond. These projects are already free cash flow positive, thanks to the proceeds from the dual exploration model, and by the end of 2025, they are expected to generate more than $24 billion of cumulative cash. In addition, this project offers significant upside to our business. At $70 Brent, the IRR is 18%, without including the upfront cash inflows from dual exploration model. Our portfolio is not only material and valuable, but also resilient.
The 2.7 billion of equity reserves pertaining to these 14 major projects have a CapEx per barrel of around $12 and an average breakeven of less than $30 per barrel. Our underlying cash generation growing over the next four years, even a flat scenario, and it will be further enhanced by the oil price recovery. In 2018, we expect underlying cash flow from operation before working capital of more than EUR 11 billion, EUR 1 billion higher than 2017 at a constant $70 scenario. This increase will be driven by all businesses, with upstream contributing EUR 1 billion and midstream contributing EUR 0.2 billion-EUR 0.3 billion, partially offset by other costs, including renewables.
The 2018 reported cash flow from operation is projected at EUR 12 billion, benefiting from working capital contribution in the range of EUR 0.4 billion, as well as the cash-in of the deferred price of EUR 0.5 billion related to the 2017 Zohr disposal to BP and Rosneft. Overall, at $70 in 2018, cash flow from operation is expected to cover 1.6 times the yearly CapEx. In 2021, at constant $60 per scenario, underlying cash flow before working capital is expected to increase by more than EUR 2 billion versus 2018, to more than EUR 13 billion. Rising production and margin expansion will generate an additional EUR 1.5 billion cash-in from upstream, while the mid downstream growing businesses, including renewables, will contribute the rest. Under $70 per barrel scenario, the underlying 2021 cash flow from operation will increase by further EUR 2 billion. Cash neutrality is a different but powerful way to read the cash flow projections.
Cash neutrality means, by our definition, the Brent price and the euro/dollar exchange rate needing to fully cover all OpEx, G&A, interest, and CapEx supporting both the production growth and the mid downstream expansion, as outlined in our four-year plan. In 2017, we achieved cash neutrality at $57 Brent with 1.13 euro/dollar exchange rate. In 2018, we are projecting our cash neutrality to decline to $55, despite the devaluation of U.S. dollar to 1.17, it will fall further to $50 per barrel by the end of the plan period, thanks to our sustainable growth, margin expansion, and capital discipline. This is the most important metric we can use to measure how resilient, as well as cash generative our portfolio is.
We are approaching now the end of our presentation, before detailing the distribution policy, I would like to compare the main 2017-2020 targets set in this strategic plan versus the previous one. Thanks to the 2017 performance and the ongoing effort reflected in this plan, we are now in a position to announce the majority of them. As far as the industrial metrics, while we confirm our outstanding exploration expectations backed by the long track record of discovery made so far, we expect the production growth rate to be slightly higher than 3%. Furthermore, we are lowering the already competitive project break-even by a few dollars and increases by 40% the LNG volumes to market by 2025. In terms of organic cash flow generation, we announced all of our targets while CapEx remains flat.
Finally, on top of the Zohr 40% disposal, not included even in the original target, we have already completed around EUR 4 billion of additional sales, we are targeting a further EUR 1.5 billion by 2020, mainly from our recent exploration discovery. Again, applying the dual exploration model. In so doing, we are significantly strengthening our balance sheet while diversifying and enhancing our portfolio. Now let me focus on our remuneration policy and more generally, our cash allocation priorities. The progress we have made in consolidating, integrating, and ultimately expanding our businesses is well advanced, and the effects are already visible in our 2017 actual numbers. Looking ahead, this strategic plan, targeting a material, sustainable growth and margin expansion, is solid and further de-risked.
On this basis, we are pleased to announce an increase in our 2018 dividend by 3.75% to EUR 0.83 shares, in line with our commitment to progressive remuneration policy linked to our underlying earnings and free cash flow growth. While dividends are our favorite way to remunerate shareholders, share buyback remains a flexible way to return to shareholders the cash in excess of the leverage target. Now I leave the floor to Claudio for his final remarks.
Thank you, Massimo. To conclude, in the past four years, we have transformed our company, setting a strategy that fortified Eni, both operationally and financially, as we saw. Now we are entering a new renewed phase of industrial expansion and enhanced shareholder returns, driven by a deeper business integration and a relentless focus on efficiency and capital discipline. We will deliver a low-risk, high-margin organic growth in the upstream, a sizable diversified and competitive LNG, a further upgrade in all our mid downstream businesses, and overall, a long lasting and growing portfolio. In a world that is demanding a lower carbon footprint, we believe that our low-cost resources, our global exposure to clean natural gas, and our unique business model in renewables will be a distinct competitive advantage.
The dividend increase we announce today, in line with our commitment to a progressive remuneration policy, is a result of the business and financial improvements achieved so far, as well as our confidence in further value growth. With this, we conclude our presentation. Now we have a video that gives some summary of what we have said, to figures. We can start Q&A with Massimo and our top management present in the room. Thank you.
Morning to all. Now we are ready for the Q&A. Just to remind you, in the afternoon, we will have the breakout session with the senior management. You will have a further opportunity to ask additional questions specifically for each business. Before starting, please, for the benefit of video, stand up and state your name before making your question. We are ready. Jon?
Good morning. It's Jon Rigby from UBS. You highlighted the change in distribution policy, particularly with regard to the buyback, albeit that you've also increased the dividend. You sort of then passed over it a little bit. I just wonder whether you could go into a little bit more detail about the process that will encourage you to start, the conditions that need to exist, and how long you would expect to be wanting to buy back stock to make it worth your while to launch into a program in the first place. Something around about the scale, et cetera. One other just little point on the outlook you were giving for the chemicals business, because at the margin, some of the cash flow contribution from the mid and downstream is quite important. I just wonder what encouraged you to assume that conditions actually deteriorate from 2017.
Global economic growth is pretty good. I just wonder whether there's anything in your particular chemicals mix that makes you a little bit more conservative of a view, or should we regard that as upside? Thanks.
Thank you very much. Just a few words about the dividend policy and the share buyback. I think that we opened up and we gave the conditions related to the level of our leverage. If we are below this level, the level was 0.2-0.25, if we are below the 20%, we can start the share buyback. We don't disclose at this moment the timing and the conditions. The main issues today were to announce the increase of our dividend, that we will also explain that we have a trigger to be able to open up also on the share buyback. There is no more disclosure. I don't know if you want to add anything else.
In 0.2, 0.25, that is the same target we announced in the previous occasion. To start up the buyback, we would like to see our leverage steadily below 0.2. That is something that we can figure out looking at the number of the plan, in this case, buyback would remain an option to be considered.
Okay. On Chemical, Daniele will answer the question.
Yes, Jon. On the chemical business, we are particularly confident the condition in terms of growth will continue to be favorable, but we have banked in our plan a couple of elements. First of all, there is a big U.S. wave of cracker based on ethane that are coming on stream between 2018 and 2019. This is about roughly 10 million tons of new polyethylene capacity that will be put onto the market. This will clearly go to Asia, will clearly go to South America, but a lot will come to Europe. We already saw that during quarter four and quarter one. The second part is a lot of export we do to Asia in terms of ethylene, which didn't happen in the past and is happening now for the next couple of years. Asia is gradually becoming independent in terms of cracker as well.
Factoring these two elements in spite of a reasonable growth of demand for our product, we needed to be more conservative.
Okay. Thank you.
Hello, it's Tapan Jostling in from Exane BNP. I had a few questions, please. Firstly, just could you come back to us in terms of, you labeled the point around CapEx flexibility. I wanted to understand or have a recap in terms of where that CapEx flexibility now is within the four-year plan. In particular for 2018, what do you incorporate for Mexico because you still have a high stake?
Mexico?
Yes, please. The second question comes back to also portfolio. You didn't necessarily sort of increase the plans for disposals. You also highlighted a reduction in North Africa. I wanted to understand whether going forward, you see more, when we think of portfolios, asset swaps rather than outright disposals.
Thank you. We're going to answer your first question in terms of flexibility. 2018, we are going to carefully finalize all the FID that will guarantee the growth. Most of the FID is already done, for 2018, we have a small, clearly, it's more flexibility, but the level of 2017 Eni CapEx is really low because it's EUR 7.6 billion, it will reduce further our upstream. For the rest of the plan, we have a flexibility more or less about 50% of our CapEx in terms of adjustment in case of worst scenario. Mexico, as we prepare the FID, I hope in the second quarter, the investments are incorporated already in the plan, will be delivered in the second half and beginning of 2019.
To give you some more numbers about the flexibility all along the plan, as Claudio said, in 2018, we are going to take the five FID that will allow us to reach, together with the ramp-up of start-ups already existing, the production growth by 2021. It's a crucial year, I would say all these CapEx are really considered committed because it would be not realistic to assume that we can still move our plan. In our more or less 35% uncommitted CapEx all along the plan, 2018 is considered already committed. By the end of the plan, 2021, this level of uncommitment is in the range of 50%. Just a comment about the disposal. Now disposal is not something that we consider we must do.
We never consider as a must, definitely is the right way to manage the project in which we had 100%, in order to de-risk, to have a better shape in our project, a sort of dilution without losing the operatorship is something that is reasonable. The possibility to have a swap instead of a cash in, as we substantially demonstrated through the latest transaction, could be definitely a reality, even to shape a little bit the portfolio and to move the portfolio towards the direction which we believe it should be.
Oswald and then Rob. Mexico, I told you.
Mexico, CapEx, we are including. Mexico, the partial dilution of Mexico is part of EUR 1.5 billion additional dilution we are figuring in this plan. Let me say that specifically in 2018, CapEx for Mexico are not a huge number because we are still waiting for the final approval from the government. That is expected in weeks, but we are in March.
Hi. Thank you. Oswald Clint at Bernstein. I just wanted to ask two questions about the slides. The first on gas and power. The EBIT is quadrupling by the end of the plan, but biggest chunk it looks to be in retail, in the rest, in the LNG parts, and you're also talking about expanding quite aggressively within LNG. I wanted to know, can you talk about that LNG portfolio? Are these all long-term contracts? Are you restricted in the profitability of your LNG portfolio? Can you optimize it better and maybe unlock some greater LNG earning power from this growing portfolio? That's the first question. Secondly, just on the digital solutions and initiatives, the 7% OpEx reduction, the kind of 30% non-productive time reduction. Are those numbers all within these cash flow targets?
By 2021?
Yeah. Okay. Firstly, a general introduction for LNG when you talk about flexibility. Our model is really the model toward getting all the equity gap covered by our LNG portfolio. If you look at our target in 2021 of 12 million ton per year, eight million will be equity. Clearly, that is not just giving us the possibility to be along the chain and getting all the advantages to be along the chain, but also having a strong grip on the upstream to give the flexibility. In the upstream, give you the flexibility during the commercial phase, because you talk about the gas that you are going to produce, and you are sure about your production. Otherwise, when you sell gas that you are not producing, you cannot be sure, so you cannot really guarantee your buyer.
For the buyer, we saw in different phases, but the last one, 15 years in Pakistan, with our LNG from Jangkrik, the fact that our production was on hand, and we had the flexibility to be able to give our production or leveraging other production, was essential also to win this contract. I think that overall, the strength of being all together is absolutely important. First of all, because upstream is more than 60 countries, where we know we are a legacy position, so the gas and power can take advantage. Secondly, because from a commercial point of view, we give us a strong flexibility. We do not have a particular reduction using this model. We have an increase of our margin. That is clearly because we are in the upstream. If Matthew wants to complete and give some additional details about the growth.
The only thing is that I can underline is that there is no specific restriction. If you saw the slide before, we were considering 30% of equity production in 2017, and we are going to 70%, unrestricted, later on. That is fundamental. In addition, we do have an advantage of having a geographical diversification with LNG, and we are already using that quite a lot now. We do see improvement in our transportation, which we did.
Digital. Now we are.
Yeah. Digital.
Be careful. It's not falling. It is not my fault. Digital is included, or partially included. We risk some value. Clearly, we can have some more advantage because we are accelerating the phase of sensors and what we call digital twin. Digital twin that became essential for operation, really for our predictive maintenance, but also for asset integrity, that is a crucial issue for us. It's included, but risk, I think that we can have some upside potential because we are growing faster than what we thought in terms of sensor and also algorithm and creating a centralized control. The answer is yes, that we can have some upside. Now it should be Rob.
Hello. Rob West from Redburn. Thank you for the presentation. I'd like to ask you about North Africa, if I could. The details you gave us were for a shift away from that region. I think you said 39% to 31%.
32.
32.
Yeah.
What's behind that? Why are you shifting away? Is that simply what's in the plan as you communicated it, or is there anything that could change in that region in terms of the projects you have access to or stability or terms that could make you want to accelerate there? Thank you.
Thank you very much for your question, Robert. I don't want to create any kind of ambiguity on that. We are not running away. We are not shifting away. What is happening is that we are increasing production in the Far East and in North Africa overall, Libya is reducing the rate, production rate. Remember, Libya, we have a rate that was above 100,000 barrel per day. Now, at the end of the plan, this rate will be about 200,000 barrel per day. It's going down, Libya. Why it's going down, Libya? Because for eight years, we had a very good rate, but we didn't invest in new projects. We just invested in HSE and asset integrity. That's all. No production optimization, no new project. Now we have started developing new project. We have one project that we start now in offshore.
I think that we already got a very big result in keeping the production steady. But now, after this peak year, Libya is going down. We are not shifting away or running away or pull out. We are increasing Far East, Indonesia, especially. We are increasing now with the new entrance in Abu Dhabi, and Libya is going down. Clearly, Egypt is going up. But that is the more or less the situation in term of figures. Yeah.
Hi. Iain Reid from Macquarie. Just a couple of things on LNG, Claudio. Firstly, five FIDs. Does that include Mamba this year? Exxon were very positive about it last week, so maybe you can update us on the current plans on that. Just coming back to Egypt, you've clearly got an unused LNG export facility there, and you've got a lot of gas in Egypt. When are we going to see you start that up? And is there any impact on what's going on in Spanish utilities in terms of your plans on that?
Okay. Yes, ExxonMobil said 2019, the FID, we are very happy and ExxonMobil is in charge, is the operator of onshore of the LNG or the midstream. We are following them. Clearly, all the packages are almost ready. We already practically made, in this period, everything. We are just discussing for a possible upgrade of the quantity of each train. What I can say about our calculation, that will be 2019 or 2020, no later, because we have to really capture the good wind of opportunity for LNG that is growing dramatically. I think that if it is 2019, we are very happy about, and we follow them 100%. LNG in Egypt is a possibility, is a reality. I think that is something that is going to happen. Why? Because Egypt is not that poor.
You saw that two days ago, we issued a press release about Nooros. Nooros is a field that we discover with Zohr same time, that now is producing 1.2 billion scfd per day. It's really a huge improvement. Time to market, few weeks, one month, because we are using our existing facilities. Now we are going to upgrade and give more space, and is improving. Between Zohr and Nooros next year, we can add overall, yes, 2019, we can add overall four billion scfd a day. That clearly, we are absolutely overcoming the internal consumption. Having Egypt is big opportunity to have good cash flow from LNG. They have about 17, 18 billion cubic meter of LNG exports. I think that by the end of 2019, I think that we can start, in a couple of years, we can start exporting gas from Egypt. Irene?
Thank you. Irene Himona, Société Générale. I had two questions, please. First, you retain your CapEx flat over the plan, although your oil price assumption, I think, rises.
We reduce a little.
Yes.
Yeah.
The oil price rises a little bit to EUR 70, EUR 72. I wonder if you can talk a little bit about industry cost inflation and perhaps what you assume in terms of Eni's cost inflation, because clearly you have a new development model, and it would be interesting to hear about that. Secondly-
Right
in the context of the 3.5% targeted volume growth, you've had some operational issues in the last couple of years at Val d'Agri, Goliat. I presume that is a risk, 3.5%. I wonder if you can talk a little bit about the contingencies that you allow in that plan. Thank you.
Okay. The first question about cost, I think I'll ask Roberto to give some light.
Yes. In terms of cost reduction due to contractual negotiation and contractual activity, just to give you an idea, last year, we were able to achieve almost EUR 300 million of cost reduction. That means almost EUR 1 billion in a four-year plan, thanks to renegotiating some 450 contracts and the re-tendering activities. Overall, we are talking about 900 contracts. What we have seen in the market is that services continue to be in the low side. Materials and equipment are increasing their prices, because basically the steel is increasing. Overall, is not as a couple of years ago, but I would say that drilling rigs, logistics services, et cetera, are still in a low side.
Yeah, we have 4%, more or less, inflation in our CapEx. That is not very dissimilar in any way from what we projected last time, because the scenario we have in mind this year is more or less the similar scenario we had last time. The level of contingency, we have about, overall the plan, about 3% of our full production, that is a contingency, from 2% or 3%, that is an average. Talking about Val d'Agri, we really think that the problem is behind us. Val d'Agri now is a month to month. That's producing without any problems. For Goliat, I think it's the same. The downtime of Goliat was very high. Now after the last stop that we had in October, November, the production is steady. From December on, the production is steady.
All the discussions with the stakeholders and with the authorities are absolutely in line with the expectation. We have a maintenance schedule for end of August, September, so that we have a couple or three weeks that is in mandatory maintenance program. Also for Goliat, we think the problems are behind us. Thomas?
Hi, it's Thomas Adolff from Credit Suisse. I have three questions. First one is really around the positive as well as the negative surprises you saw in 2017 in running the company. The second question is on benchmarking. As you benchmark yourself versus peers, but also versus other industrial sectors, what are the areas where you can still see significant improvement within Eni? I guess the third question is, being a CEO, you're very busy. I wondered how you manage your job as a CEO and having to go to court related to the Nigerian issue. Thank you.
Okay. 2017, the issues in 2017, I think that has been our operational issue that we have just mentioned, and that we have been able to compensate, accelerated, and making, I think in term of production or M&A or a new project. Not just existing production, new projects, we compensate, and we have the best cash flow ever. Just can jump into the last question. I've been so occupied on that I don't think one second to the Nigerian case. Otherwise, I couldn't do what I did with my people, with me, and I can't do what I'm doing for the company. One thing was certain was I'm so relaxed about that because I know what we have done. Now we have the possibility to explain, because there is a trial. All the space is for production, for projects, for our shareholders.
I don't think about me. Me, I think about me as a company, that's all. Upside potential. I think that the upside potential are in what is new, for the first time during the starting presentation, has been I think amplified as a more vocal and more elaborated. That is the digitalization, is the renewable, is the carbon, is the low carbon assets. We think that Eni, in this case, has a big advantage. First of all, because we started as soon as I arrived with the renewables, with a very strong model. That is not just giving us 10% of return. The 10% of return that is high for the renewable is very good, but what is giving us a very strong presence in our legacy country, because now we are giving a different energy mix.
Mix. We are developing in our facilities or outside our facilities, but in the country where we operate, we are giving wind power, we are giving renewable power, we are giving through the renewable water. We are making free gas. That before we use, and a huge amount of gas, because we are consuming more than 4 gigawatts for our internal consumption. Gas that use to run turbine or pumps or other kind of equipment, now begin to be the Mexican market. Clearly, it's good for us. We are reducing cost. That's good because we change the energy mix. This gas is going to replace what coal biomass that they are using, and that is killing people. I think that the 10% is nothing respect to the big improvement in terms of relationship.
It's developing very fast because we are signing project in Ghana, in Nigeria, in Egypt, in Tunisia, now in Angola, in Congo, then in Mozambique. Country that don't have energy. That is a good way to give a good energy instead of giving or let them die using the biomass. I think that is the bigger side. The other upside that is more technical is digitalization. We are going so fast, and this also as a 10% is nothing, for the renewable in terms of return. Also, the reduction of, when we talk about the reduction of CapEx or OpEx, to the digitalization or the improvement of the time to market for exploration is nothing to respect to what, for what we are giving to our people and our projects.
We are already in the top level for HSE, using drone, using robotics, and using other tools to manage and work on the installation. We are really reducing drastically the risk for our people, and we reduce drastically the risk to have a shutdown, to have a corrosion, or to have any kind of stop in our equipment. There, that is an upside potential. For us, for everybody, but it depends on the rapidity and on the focus, and if you believe in it. You believe that you have to change your energy mix. You believe it is just a fashion. You believe that you use digitalization is just a fashion. We think that we need it, is not a fashion, and that is our upside. We believe in that. Thanks, Thomas. Mark and Chris. Sorry, Mark and Biraj.
Hi there, everyone. It's Mark Coughler from Jefferies. I just wanted to ask a quick question about the dual exploration model and how the board thinks about that. I suppose really, the competing interests around production growth and cash flow growth. What's driving the policy in that sense, and how significant is the 3% plus production growth in the long term?
Yeah. If I well understood, your question is, if there is any competition about Dual Exploration Model in our growth, in our replacement ratio, for example. There is no, we have figures because in the last 3, 4 years, we sold, it's at $10.3 billion, $10.8 billion of Dual Exploration. We had an average replacement ratio of 130% in our reserves. Without that, we can have 200 maybe, but the concept is, we are not damaging our resource base because we are replacing more than 100% our production with these assets. It clearly is a strategic choice, it is a choice to acquire 100% stake in the asset. Mexico is a clear example we were discussing before. We are 100%. We take an FID, we start producing, we have a good asset to swap and diversify our presence.
What happens now, Zohr, where we have a big exposure, now we diversify. You create a dynamic that you can use to manage your business. It's not damaging. The country is really giving much more value. Clearly, you have to start from a high stake. When you start from a high stake, you have to be able and ready to take this risk. Why you take this risk? Because you invested before to be ready to take this risk. It is a change. It's not something that you can start overnight. I started talking the first time in London in 2011, 2010, about the idea to be an explorationist inside a big company to really use this model. All the countries, small companies that are fewer explorations does. I think that is something that is being built.
It's giving good fruit and good results, there's absolutely no competition. The 3.5% is very robust one. It's an improvement of 3% respect of the previous plan, is an improvement based on organic growth. It's just 4% this year because you have this 45 average barrel production, 45,000 barrel that coming from Abu Dhabi. There is absolutely no, if they are working together, exploration, development, and production are absolutely overlapping, and that is our model.
Okay.
Hi, Biraj Borkhataria, RBC. Two questions, please. The first one is on the geographic mix again. A lot of your exploration success in some of the recent growth has been from Egypt. I was wondering how you think about that over the medium term. Is there a level of production or capital employed relative to the group that you would be uncomfortable being in one country? Just some thoughts around country risk specifically. The second question, I think I heard you right in saying, in addition to the growth, there's an element of production optimization that's going to come through in the volume numbers over time. Could you just explain what exactly that is and quantify that?
First of all, I give the floor to Massimo. I want just to tell you that all our exploration is not just coming from Zohr and from Egypt. Our exploration is coming from really a diversified number of countries. All these big figures of exploration is coming from Asia, from Kazakhstan, from Norway, from the U.S., also Mexico, from Congo, from Angola, from a different country. I'm talking about the past, but also for the future. It's really coming from Middle East, from 25 countries, it's not Egypt. There is a good distribution of our investment. If you want to maybe to elaborate on the distribution of our capital, so exposure.
The same. In terms of exploration, based on this figure, you can understand the exploration CapEx are very well spread. The same, I would say, looking ahead, because if we take a look at the most important CapEx projects we have in front of us to get the increase. Thinking about Coral, thinking about Zohr, thinking about Mexico, thinking about Jangkrik and Merakes in Indonesia, they are very well spread. These are the production coming from the new project. While from the, I would say, what we call the maintenance, from the number I already gave to you, we spend more or less EUR 2 billion every year in maintenance and production optimization, and the overall contribution to the production growth is in the range of 200,000 barrel per day by 2021. You remember Claudio said 700,000 barrel per day coming from project startup and ramp up.
On top of this, 200,000 is coming from the production optimization.
Thank you. Scott Cooper from Bank of America. 2 questions, please. On your dual exploration strategy, do you think Goliat could qualify as a potential opportunity for farm-downs now that uptime has stabilized, as you said. Also wanted to hear whether you can give us any more detail around the running time at Goliat, what it is today, considering you sound like you're happy with the performance there now. The second question is, I've noticed throughout your 4-year plan, you're using the same standard refining margin assumptions. Does that mean that potential upside from IMO is something you would expect to see to come on top? Should we then expect, if that upside occurs, to be returned to the market via buybacks? Thank you.
Thank you. No, Goliat is not in the exploration phase. It's an old guy now, it's not really something that we consider for an M&A. The uptime is good, the downtime is very low. There is no downtime in the last three months. It's very good. The expectation is to have something around 5%-6%, that is a normal average considering what we schedule as the maintenance. For refinery, Pino, you want to answer? Just the question is IMO is included now, that why we are the same kind of oil return. It's not true. The R&M is increasing. It's increasing, you see. R&M is increasing because at the end of the period, it's going to deliver almost EUR 1 billion, R&M both together, 50/50 more or less.
That means that considering starting from now, that is less than EUR 100 million, it's increasing. It clearly is increasing because IMO is included, we think that from our point of view, IMO is very advantageous for us because we have all the refineries that can cover this kind of low sulfur content. You ask if you want to increase? We increased today. I think that we are incorporating IMO today in the remuneration policy. Alessandro.
Alessandro Pozzi from Mediobanca. You presented a slide on the cash flow break-even reducing significantly to almost to USD 50 a barrel at the end of the plan. Production growth is the main driver, probably that's also supported by downstream and midstream. I was wondering if you can provide more color on those elements. The second question is going back to CapEx. Can you provide a geographical breakdown, probably Mozambique, Mexico as well, are going to be a large chunk of the CapEx in the next four years. Thank you.
Massimo, can you answer? Roberto answer to the CapEx breakdown.
Give me some time to Time for what? To have the breakdown in the CapEx by geographical area. We can answer on the cash flow per barrel, no? Okay. As far as cash flow per barrel, the decrease is mainly related to the upstream, and is related to the unit margin per barrel that Claudio shown in his presentation. You have seen the margin going up, and if you compare that line with the line that we show last time, you can see an upside. An upside that will be even in the first year and then projected by 2021. On top of this, we are projecting some contribution from the digitalization. I would say some, because digitalization for us and probably for the world today is like a fast car, so it's very difficult to take a picture.
Anytime we discover additional application of this digitalization. The number that we are showing right now is just what we can see now in terms of application, in terms of spreading around the techniques. Definitely, every month, every quarter, we will see an increase in this number. What we are showing today is the picture we can see right now, that is quite comfortable because $50 per barrel by 2021, something that leveraging, basically on an upstream portfolio, is something that we consider definitely outstanding. In terms of breakdown, this is very high. Okay. We are talking about the total investment. This is the developed investment. Overall exploration to development. Exploration plus development. This is not the total, right? I can answer. It is too long.
In terms of the four-year plan, you can go to make your calculation. The main investment will be clearly now reduced. The first is Egypt, clearly. That is the first investment. We have investment that is in detail, that is in Ghana because we are finalizing, and we are going to put in production the gas portion in June. We have Indonesia, not large investment, but we continue to invest in Jangkrik. Now we are going to invest in Merakes. That is new big field that we are going to join to Jangkrik to go to Wuhan. We have investment. We're going to have investment in Norway, because in the three-year plan, we start Johan Castberg, and that is an investment where we have a stake, and it is a very important one.
We are investing in Libya, as you said, because we are going to invest in Wafa, in the offshore, because we have to at least the new investment, what we are going to happen with the investment, we are going to fight the depletion, because we have a larger depletion rate there. We invest in Algeria, we invest in Alaska. After the deal, we are doing well, we hope that we can tie in, there is a plan for this investment. Clearly, the big investment in Egypt is Coral. Coral Mozambique, because we are developing Coral. Now we have reduced because we have 25% of a big, big stake, but it's 25%. We can say that we have investment in North Africa, Egypt, East Africa, Mozambique.
We have Far East, we have Middle East, a little bit later, because we have to double the production of the fuel we acquired. We have Kazakhstan, we have Norway, and we have Sub-Saharan Africa and Mexico. Mexico, that was not a super investment because it is shallow water, but it is investment that can bring about 100,000 barrels a day. That is the map of our investment.
I did the page, so I can provide the details after.
We can by mail. Yes. In two, three weeks it will arrive.
Through the supercomputer. Libya.
Thank you. It's Lydia Rainforth from Barclays here. Two questions, if I could. Partly coming back on digitization. If I look at the cash by barrel chart, again, it is the legacy barrels that actually seem to be higher cash margin than they were a year ago. Is that where you're seeing the bigger benefit of digitization in the legacy barrels versus the growth barrels? Then, related to that, you've given the target of 7% reduction for production costs from digitization. Is there a similar target on development costs as well on that?
Answer your answer, I answer. Up to you. I give just the first part of the answer. That is on OpEx, because in the development cost, all the digitalization of the new project is already incorporated. It's in the EUR 12 per barrel that we got, that Massimo told you before. In the new project, it's incorporated all the sensors, all the algorithm, all the centralization, and control on rigs, equipment, and pipes is already there, so it's not included. For that reason, we talk about in operating cost. On the legacy assets, clearly what is impacting is operating costs and maintenance. I think that we kind of have some improvements, because we are going to replace pumps or pipes or all this kind of stuff, and that will be optimized in the future. That is not included in the cost reduction of the asset.
Yes. Definitely on top of this, what we can project now is already included in the numbers. Definitely is reasonable to expect something in the range of half a dollar in term of OpEx reduction applied definitely on the operating activity right now, because what we are doing, as you've seen, our target to start from our activities now 30% towards 100% by the end of 2021 or even before the date. Massimo?
Massimo Bonisoli from Equita. A couple of questions. One, regarding your current setup of businesses. Following a few years of restructuring and downsizing of the mid downstream, your exposure to that business has been reduced materially and now is lower than the average peer. You presented today a CapEx plan in which the upstream takes more than 80% of the CapEx. Do you feel confident with the current setup and the exposure to the mid downstream, given the fact that reduce the volatility of your earnings compared to the trend in the oil price? The second question is for Daniele on Versalis. Over the past few months, there were a few rumors on the eventual acquisition in the business.
I don't want you to comment on those rumors, just on the natural evolution of the business in the chemical space, considering what you have reached in terms of restructuring so far.
Going to the first question. It's not true that now we reduce our capacity in downstream, and now we are smaller than the others. We have been always much smaller than all the other peers, because now we range about 700,000 barrels per day. The other have 2 or 3 or 4, 3, 2, 1.5 million barrels per day of refining capacity. The only difference now, we are not losing money. That is the only difference. That now is small, but it's making EUR 1 billion. That is the difference. We improved. The question is, are you happy with your improvement? No, I'm not happy. When we discuss that is a phase of expansion because we restructure, so we know what we have in our hand now, and we can expand, especially outside. I think that is the next step.
We are not admitting that we have to increase, but increase in a very rational way, not buying. Everything must be linked. When we talk about integration, I don't want to have any kind of refinery if we are going to have additional refinery. We are working in Nigeria, so in Angola, but working to help and link our oil to the existing refinery. The model is integrated. If I have a refinery, I must have also the upstream production. That is really the business integration. Then, Daniele.
Yes. In terms of the chemical business, you know pretty much the story. This business was broken, we had to fix it. We did it. We went from a massive loss of EUR 400 million, EUR 500 million per year into the result that you're seeing today. What is the next step now? It's to grow the business through three leverage, fundamentally. First of all, to benefit from the integration. Any hydrocarbon stranded opportunity we have around the world together within the group, we do it. Algeria is an interesting example. We signed an agreement to explore this kind of integration altogether, and there will be more of that. The second one is leveraging our technology on an international basis. We have clearly over 290 proprietary technology left from the past that we continue to leverage. LOTTE is a classic example to be present in Far East.
The third one is the specialization in our existing assets. If you want to compete, we are in Europe, we are strongly present in polymers, automotive, electronics. They always require new polymers and new technologies, and the product has to evolve. Otherwise, we remain on the last of the supply rank. That's the three leverage we have to grow this business.
Thank you. I think the last few questions, Lucas, that was probably waiting for a while.
Yeah. Thanks very much. It's Lucas Herrmann at Deutsche. Maybe it stays in some ways with Massimo's question around the downstream, but it's actually about the structure of cash flows, and the way you think about the structure of cash flow in the upstream, because in some respects, you said-
In the downstream, in the upstream?
In the upstream.
In the upstream.
In the upstream, I'll come on to it. In some respects, you are disadvantaged relative to peer, and that the cash flow that comes from sizable downstream operations for others is more material than it is for you. That obviously provides an affordable support with dividends. In the upstream, your business historically has also been more conventionally biased. I can see that the shape or the duration of the portfolio is improving as Zohr comes through, as to Western Libya Gas Project and the deal you did with Abu Dhabi. Claudio, when you think about the portfolio going forward, and this is not short, this is long, how do you want the shape of cash flow in the upstream business to appear?
How much duration, to use that term, would you like to see relative to where you are today to give you, let's say, better protection, comfort through the kind of market volatility we've seen in commodity over the last two, three years?
That's what we have done in the last three years. That was really to be more focused on our E&P, to create an E&P that is the 80% of our business, that also can prepare the company for a downturn. That's what happened. What happened, because now with the new target to reach $50 cash neutrality, Eni, that's a $36, $37, $38 for the upstream. The work that we have done on the assets, on the development model, on the production. Everything that became very powerful, very strong, but at the same time is reducing your cost and create a longer life for your assets. Because for us, really, the advantage is really to have a long life, to be able to increase the margin, and that is our defense. We work on that. We continue to work. Meanwhile, we work on the iron oil and chemicals.
They are really now good partners of the upstream, not just good partners, they work together, and that is an additional defense or part of our resilience looking forward. I think that during the presentation, I mentioned something that is very important and is very good for the future. During the downturn, we have been able, okay, to find 4.4 billion, but we have been able to increase it three times our acreage. We have done that very quietly, without big noise, because if you make some noise on that, somebody else is going to compete and increase your cost. Increase of three times expected 2030. That means in terms of potentiality of un risked equity, a reserve 10 billion barrels.
For that reason, that is an additional big potential that Eni has, because we can start a really new age, like we did in 2011, 2012 or 2013, when we start a new age, but our acreage was less than now. Now we are really a good acreage and three times more, and that is the real strong defense because now this flow of exploration is coming in a structure that is ready to getting these new reserves in a situation that is much, much better in terms of robustness and readiness. I think that for that reason, when we say we are looking forward, and we are looking at the future in a different way, really, in a more aggressive way, with a lot of discipline, but a lot of good, positive weapons in our castle.
The last one to Martijn.
Yeah. Hi, hello, it's Martijn Rats with Morgan Stanley. I wanted to ask you two things. First of all, I wanted to ask you a bit about your macro thoughts.
Yeah.
About your macro thoughts. In the sense that at the back of the slide deck there is a time series which shows oil prices going up to something like 70, 72 by the end of the planning period. I think Irene sort of also pointed it out. At the same time, we talk to a whole lot of oil companies, and breakevens are falling everywhere, and rising prices and falling breakevens. I mean, the divergence, particularly by the end of the planning period, gets rather enormous. I was wondering how you see that playing out. Are we eventually going to look at an industry where perhaps the very low breakevens will not be able to be maintained? Or are perhaps some of these higher oil prices ultimately a little stretched? I'm just wondering how you see that divergence between rising prices and falling breakevens.
The second thing I wanted to ask, a little bit following up on Chris's point on the IMO. There is also an emerging view that the benefits of IMO will ultimately not accrue to the refiners, but simply to the people supplying the crude, with sweet crudes going up an awful lot and sour crudes going down an awful lot. Shouldn't you put the benefits that you put in your downstream business, shouldn't you put the IMO benefit into your upstream business?
Thank you. You can answer about IMO. The macro scenario, you saw that in this strategy, we didn't highlight our scenarios. We treat the scenario as something that every day is, because we have to run calculations for the future, but we run all our tests at $60, just to show the robustness, and the robustness and the strength of our asset base. I cannot talk for the industry. What I can say that the choice we made in the past in terms of asset base is our strength. What I mean that our cost, if you ask me, can you keep this cost also the price going to $100 per barrel?
I can say that looking at the split of our investment for the future, when we have the flexibility to, or we don't sign yet a contract on FID, we have still chapters that has to be closed completely in the contract. I think that we have absolutely the possibility to keep our breakeven very low. Our breakeven trend is now linked to the oil trend. At least, it can be linked at about 20%. The 80% is linked to the strength of the asset and the cost of the asset, and now much more than before. Every age is better because the structure, as you said, this new exploration is ready to be started in a structure that is very robust now. In terms of processes, in terms of equipment, in terms of modernization, standardization.
There is really a certain mind, but also an insourcing of competencies now, because all the engineering, that is really a peculiarity of Eni, that all the engineering, practically all the FEEDs, and we are the main contractor, and we make all the main FEED, the front engineering at home. We are in the detailed engineering. We put people in the commissioning. For that reason, we are really stretching the time. We are squeezing the time, sorry, and we are reducing the time to market. That is the quality of the asset and the strategic choice about the exploration and the development that are really the two distinctive elements of our macro profile make us so strong there. That means that the price is going up.
We are very happy for the margin, but we are fight every day to preserve our cash neutrality, and we have all the tools to do that.
May I complement your answer to Martijn? Just to qualify that, Martijn, you are right when you say that the cash breakeven are going down for everyone in the market. But because of the difference we have just commented in our portfolio, our drop in the cash breakeven is something different because we are leveraging 90% on our E&P asset in reaching the EUR 50 we just announced. Why? For the others, you know better than me. The contribution from business other than E&P is significant, and it will be even more, in case of an additional drop in the oil price. Comparing the two, what I will say that we are very happy about the quality of our E&P. That means that whatever will be the price, our E&P will be in the condition to compete better than the others' portfolio.
About IMO.
Okay, about IMO. IMO is a strong opportunity for a refining system that use especially high-sulfur for heavy crudes, and our system is based on more than 70% of Crude like this. Also for a refining system with high conversion plants. With the rebuilding of our EST technology in Sannazzaro and other plant, what we have in Taranto and Milazzo, that summarize more than 4 million tons per year of deep conversion capacity. This will permit to produce zero bunker oil within 2020. This put a good advantage for our system. Notwithstanding this, our scenario is with the flat margin for refining for all the plan.
The growth that we have introduced in the plan that double the EBIT in 4 years, from EUR 5.5 billion in 2017 to EUR 0.9 more at the end, with the flat margin, means that we have further upside in our plant because of the efficiency of the integrations and of the pushing the bottom of the barrel conversion.
The question was a little bit more articulated because it was also for the upstream. Why maybe the upstream that have the good oil, maybe they can catch this margin.
Okay.
The issue is that it's not always regionally possible. You have to be also well equipped from a downstream point of view to be able to treat this oil that is around. It's true what you are saying. There is a double good returns for the company that have the right downstream to treat heavy oil, because we have maybe an excess of that oil, so they come to you can get a good price, and from the upstream that have the oil that is free of sulfur, and then you can get additional margin. I think that you got the point.
Anyway, we didn't assume any advantage in terms of margin. In the differential in the upstream, we didn't take into consideration this potential upside, that in case would be an upside for us much bigger than the advantage we can get from our refinery capacity.
Correct. Yeah.
Okay. Thank you. We leave the floor to the press conference. We will re-meet in the two meeting rooms with the top management for the breakout session at around two o'clock.
Thank you very much.
Thank you.