Tony Massimo will present our 3-year plan. In the afternoon, top management should answer your questions and add more details for each business. Before detailing our 3-year plan, I would like to give you an overview of the distinctive factors of today's Eni. In 2014, anticipating the downturn, we decided to transform our business model. We spread a new culture of integration and efficiency that has allowed us to accelerate the time to market and unlock value in our business. We grow organically by reinforcing and focusing on our operating model and diversifying our geographical footprints. Today, our value chain is shorter, and the synergies within our businesses have been optimized. In doing this, we moved the following levers, covering all our businesses. First, we focused on material exploration, including plays, close to existing facilities.
This model works so effectively that since 2014, we have discovered more than 5 billion barrels, and we replaced in excess of 130% of our production. We sanctioned 30 projects and further accelerated value generation by deploying our dual exploration model. Second, we completely restructured our development model, cutting time to market in our projects to half the industry average while reducing CapEx by 35%. In midstream, we successfully developed a strategy of restructuring and expansion, renegotiating gas contracts, optimizing downstream capacity, and opening new areas of growth in energy and in refining through international joint ventures. In renewables, our distinctive model is leveraging our presence in producing countries to open new opportunities. The prevailing and distinguishing factor here has been Eni's ability to act swiftly and decisively. Now let's move to the 3-year plan strategy presentation.
Integration, efficiency, and technology deployment are the main strategic levers of our operational model. These are the drivers of our new energy for long-term value creation toward a low-carbon future. First, we are developing our strong portfolio, diversifying our geographical position in 3 main areas: the Middle East, Norway, and Mexico. In the Middle East, we have seized massive sets of new opportunities by adding fast-track production, high potential resources, and ultra-low-cost refining capacity. The establishment of that energy model will create a platform for long-term growth. While in Mexico, this year's start-up is just the first step in this promising region. Secondly, we are pursuing more opportunities along the value chain, growing LNG, giving greater value to our equity gas, and developing one of the largest refineries in the world. Third, we are expanding our renewables and green businesses and designing and implementing innovative solutions based on circular economy.
Financially, we will maintain discipline, growing organically, and pursuing further efficiency driven by technology and digitalization. We now focus on technology, which underpins our business model. For us, new technologies are like exploration discoveries. Finding them is not enough. They need to be put rapidly in production to capture their full potential. Going forward, we want to capitalize on our technology even more, reducing the time to market from idea to deployment. Our innovations cover all businesses with 7,200 patents and 250 projects belonging to 3 different platforms. Operational excellence in terms of asset integrity, HSE, efficiency, and cost optimization. The big projects in Egypt, Mozambique, and Angola would not have been possible and achieved without our technology. Decarbonization, where we are investing one-third of our R&D expenditure, the circular economy for maximizing our industrial efficiency and reusing or extracting value from waste or byproducts.
In the plan, we will spend EUR 100 million, expecting benefits of up to EUR 4 billion. In upstream, we will continue to grow organically, keeping CapEx stable, and generating large amounts of free cash flow. The target average growth rate of 3.5% per year till 2022 and thereafter. Considering the new developments in the Middle East, Mexico, and Africa, we will keep our upstream CapEx at EUR 6.5 billion per year and lower our cash neutrality to $37 per barrel. In exploration, we have increased our three-year target by 25% to 2.5 billion barrels of discovered resources. Finally, a lower scenario will generate a cumulative operating cash flow of EUR 60 billion, equivalent to a free cash flow of EUR 22 billion, almost double our dividend needs. Exploration is a key value driver for our company, and we are focused on highly prospective licenses in diversified areas.
In more than 460,000 square kilometers net acreage, we have enlarged our risk potential by 20% versus last year to more than 12 billion barrel oil resources. We are drilling around 40 wells per year. We expect to discover 2.5 billion barrel in the plan, with the annual spending of EUR 900 million. Our portfolio's position is super and proven basin. Current target will be Mexico offshore, Middle East, and high potential mature areas close to existing facilities in Norway, Angola, Ghana, and Egypt. We will continue to generate early cash flow and swap assets through our dual exploration model. In 2019, we target 600 million barrel with a unit exploration cost of $1.8 per barrel. Block 15/06 in Angola is a great example of our effectiveness of the Eni exploration model and of the successful deployment of our technology.
Specifically, this give us the major advantage of being able to recognize and discover complex subsalt exploration plays. Up to now, we have drilled 21 exploration wells with an 86% success rate, discovering more than 4 billion barrel of hydrocarbon in place. We have reached a gross production in excess of 150,000 barrel per day. In the last few months, we made three material discoveries of light oil. The first two, Kalimba and Afoxé, are estimated to contain between 400 and 500 million barrel of oil in place. Just a few weeks ago, we discovered a new giant, Agogo, that is estimated to contain up to 650 million barrels of light oil with further upside. The development of this field will be fast-tracked, relying on existing facilities. It's not over yet. In the next two years, we have additional three exploration wells plus more appraisal work.
Turning to production, we will deliver annual average growth rate of 3.5% till the end of the plan. New project startups or ramp-ups will account for around 660,000 barrel per day by 2022. Of this, 50% is related to ramp-up of recent startups. An additional 290,000 barrel per day are related to expansion projects of the existing fields. In the period, we will put 18 major projects into production. We will operate 77% of our equity. In 2019, we will grow at the rate of 2.5% versus 2018 as seen in flat scenario and excluding portfolio effect. Thanks to the long pipeline of projects in our portfolio, we are expecting to grow by 3.5% on average per year also through 2025. In the last 12 months, we are strengthening our position in Norway, Italy, and Mexico.
In Norway, with Vår Energi, we have increased our production capacity and found additional potential in exploration. Vår Energi is producing now 110,000 barrel per day equity, and we expect it to grow to around 175,000 barrel per day by 2033. With new development that have an average breakeven below $30 per barrel. We have a significant exploration potential with more than 100 licenses that we are going to test over the next four years. In the UAE, we are involved in producing field, major development, and further near-field high-potential exploration activities. Our recent expansion there has been driven by our know-how and technologies that fit with the development of the reservoir of the region. The existing equity production will grow from 40,000 to 100,000 barrel per day in the longer term.
The major development in Ghasha, the largest gas hub in Abu Dhabi offshore, where Eni is the technical leader, will add more than 100,000 barrel per day of equity in the second half of the decade, with the early production in 2022. In Mexico, we will develop Area 1, with production starting up very soon in mid-2019. Overall, these three initiatives will contribute an equity production of 260,000 barrel per day at the end of the plan. We have a long list of proven projects accounting for 2 billion barrel of 3P reserves that are reaching FID in the plan. They are low cost, high value developments that will add stable cash flow and 170,000 barrel per day of equity production in 2025. More than 70% of the FID in the plan are brownfield, and in 2019, we will sanction eight projects.
Turning to Upstream cash flow, out of the EUR 6.5 billion annual CapEx, EUR 3.7 billion will be for development and EUR 2.1 for the infilling and expansion of existing fields. OpEx stays flat at EUR 6.6 per barrel, and DD&A increases by about EUR 1 per barrel over the plan as a consequence of the start-ups in Mexico, Norway, and Mozambique. With the accredited contribution of new production, operating cash flow grows from EUR 11.5 billion in 2019 to EUR 13.6 billion in 2022 at the end scenario. During the plan, we are expecting to generate EUR 22 billion of Upstream free cash flow. Coming to our mid downstream, we will double our operating interest last year to EUR 2 billion, generating net working free cash flow of about EUR 5 billion. G&P to EBIT will grow to EUR 700 million at the end of the period.
For R&M, we target further reduction of the EBITDA margin and to reach an EBIT of around EUR 1 billion by 2022. In the site, we continue to work to improve performance, and we expect an EBIT of over EUR 270 million at the end of the plan. Midstream activities will deliver a stable contribution, increasing synergies with the rest of the businesses. This will enable an increase in LNG, leveraging integration with the Upstream to capitalize our equity gas. We will continue to optimize our gas supply portfolio while renegotiating contract and reducing registry cost. Thanks also to the continuous growth of the retail business, G&P cumulative free cash flow will be EUR 2.3 billion during the plan. In retail gas, in retail, Eni gas e luce, will more than double last year's EBIT to around EUR 500 million by the end of the plan.
We target to grow our customer base in core countries by 26% up to around 12 million, driven by doubling of power customers. We will expand the extra commodity services that will account for 20% of EBIT in 2022, driving more value per customer and lower churn. In four years, we expect to generate around EUR 1.6 billion of organic free cash flow. LNG Retail future roles in creating stronger gas and power in the longer term. We are accelerating the unbundled offer portfolio and expect to reach 14 MTPA of contracted volumes in 2022 and up to 16 MTPA in 2025, placing us amongst the top players in the market. By the end of the plan, more than 70% of contracted volumes will come from our equity production, mainly in Africa and East Asia.
With a break-even price for the underlying new gas projects of $22.5 per barrel, equivalent to less than $4 per million BTU. In Refining and Marketing, we expect to double last year's results, reaching an EBIT of EUR 1 billion, including the Waste pro forma contribution. We expect to generate EUR 2.6 billion organic free cash flow in the plan. In refining, the main drivers will be strengthening the refining asset base. With the recent acquisition of Waste, we will increase our refining capacity by 40% by 2023. Optimization of our refining processes, we expect to benefit from Agogo by increasing the gross oil yield to 55% thanks to the [Extra Star by Media] and other existing deep conversion capacity in the Taranto and Milazzo refineries. Green refineries in full operation.
In two weeks, we expect to start up Gela and with the phase 2 of gains by 2021, our green production will grow to 1 million tons per year. In marketing, we target an increase in our market share in Italy to 25%, with growing contribution of premium products and green fuel, an organic increase in sales in Germany and France. Now Renewables, a business where we will continue to grow organically during the plan. We have 60 brownfield and greenfield projects for a total of more than 1.6 gigawatts of new capacity by 2022. Investing EUR 1.4 billion and up to five gigawatts by 2025. Overall investments will be made also through partnerships and financings. Our portfolio is well-diversified, both in terms of geographical footprint and technology, where we will also deploy solution development by our R&D.
In Italy, we understand the Project Italia, our industrial conversion project that generates power from renewables on 10 industrial areas. We start the renewables business to deliver a stable cash flow in the long term. We deliver an internal rate of return between 8% and 12%, and an additional upside by replacing gas consumption in our operations. Now our new target on the decarbonization. The energy world is at a crossroad of a major transformation, supplying more energy to more people while drastically reducing CO2 emissions. In the next two decades, global energy demand will grow by around 30%. Meanwhile, we have to reduce CO2 emission by 45% in order to limit the growth of global temperature to below two degrees Celsius, in accordance with the Paris Agreement goal.
Tackling this dual challenge is a strategic priority to our board and a responsible action to all our stakeholders and environment. Today, we are announcing new targets about the decarbonization process. To achieve net zero emissions in our upstream business by 2030. We will do this by increasing efficiency to minimize direct upstream CO2 emissions, and by 2025, we will eliminate gas process flaring and reduce methane emissions by 80%, and accepting residual upstream emissions through large forestry projects. Other elements of our strategy are: a growth in low-carbon sources, with an increasing share of gas and biofuel in our portfolio; an increase in zero-carbon sources, such as solar, wind, and hybrid systems; and a circular approach to maximize the use of waste and refuse stock, and to preserve and extend the life of industrial sites.
A key role will be played by the deployment of new technologies aimed at capturing and using carbon emissions. Let's talk about the two new pillars of our decarbonization strategy, forestry and circular economy. Buying carbon credits is no longer enough. We will use our scale and our geographical positions to take an active participation in forestry initiatives that will bring wider community benefit, such as new jobs and economic empowerment of local communities. This will become a structural component of our decarbonization business model. We have already created the first partnership for REDD+ project development. Our final target is to reach the potential of more than 20 million tons per year of CO2 sequestration by 2030. For Eni, the circular economy is a key driver and powerful tool for sustainable growth toward a low-carbon future.
During the three-year plan, we will invest more than EUR 950 million and additional EUR 220 million in R&D to develop industrial circular economy solutions. In our refinery sites, we will process waste biomass, not in competition with food, to produce green diesel. This is also a good example of the transformation and valorization of assets. We will produce advanced biofuels and renewable chemicals from biomasses in waste and integrate from vegetable oil and the steam from our unit crops to produce much more output. The first pilot of our proprietary waste-to-fuel technology has started in Sicily, and we will build up to three industrial plants with a total treatment capacity of 330,000 tons per year. In chemicals, we pursue an eco-design approach to maximize product recycling and reduce consumption of raw materials. All these initiatives have been implemented, thanks to the fast deployment of our technology.
Now I will give the floor to Massimo for the financial plan and distribution policy.
Thank you, Claudio, and good morning to all of you. In the next four years, we will pursue a disciplined investment program. In 2019, we plan to invest around EUR 8 billion. Of which 80% is related to E&P, while decarbonization, circular economy, and the renewables will grow up to 5% of the overall budget. In the next four years, we plan to invest EUR 33 billion. 77% is allocated to E&P, of which EUR 15 billion for new developments, EUR 8 billion for expansion projects of existing fields and maintenance, and around EUR 2 billion for exploration drilling. The upstream investment plan is also very well diversified in term of geography, thanks to the development in Middle East, Norway, and Mexico.
While preserving our short-term production growth, we also reinforced our pipeline of long-term, long project projects and new developments in Abu Dhabi, Angola, and Algeria that will further underpin our growth beyond the plan, improving our CAGR to 3.5% to 2025, versus the previous guidance of 3%. 9% of group CapEx will be devoted to further strengthen our decarbonization strategy through flaring down and increased energy efficiency project, circular economy initiatives such as waste-to-fuel project enhanced biofuel and petrochemicals, and renewables with EUR 1.4 billion in more than 60 projects for a total installed capacity of more than 1.6 gigawatts by 2022. The remaining CapEx refers to the legacy in Midstream and, in particular, same business activities. We will retain substantial flexibility in this maneuver with around 50% of our CapEx uncommitted in 2021, 2022. We envisage a modest cost inflation impact all along the plan period.
Our capital investment program is not only disciplined and flexible, but also valuable and resilient even in a stressed scenario. Current portfolio of Upstream projects in execution, covering two-thirds of the 660,000 barrel per day production increase by 2022, is even more profitable than before, with a new breakeven price down to $25 per barrel and an overall internal rate of return at any scenario of around 22%. A significant improvement versus the previously given guidance of $30 per barrel is due to the quality of the incoming projects recently sanctioned, as well as the contribution of fast track and phased development concept applied to the projects underway. This project portfolio is already free cash flow positive, thanks to the proceed from dual exploration model. Excluding this contribution, the payout will be reached in 2021. Our project portfolio remains resilient and competitive under both weak and low carbon scenarios.
In case of 20% reduction of the hydrocarbon prices, the internal rate of return remains above 19%. When applying Eni's low carbon sensitivity of $40 ton CO2 price in 2015 real term, internal rate of return declines only marginally in the range of 0.5 percentage points. 2019 cash flow from operation before working capital is expected at EUR 12.8 billion, showing a slight increase versus the EUR 12.7 billion recorded in 2018, despite the higher scenario of last year that accounted for around EUR 0.8 billion. Considering a flat scenario 2019 that implies Brent price of $62 per barrel and the gas price at Italian hub of EUR 166 per 1,000 standard cubic meter, similar to 2018, our cash generation grows strongly over the next four years.
In particular, 2019 cash flow from operation is expected to increase around EUR 1 billion versus 2018, thanks to the Upstream volumes growth and improved production mix, resulting in a cash flow per barrel increase of around $1 from $18.5 to $19.5, and overall growing contribution from Midstream, mainly driven by Refining and Marketing. 2022 cash flow will further increase by EUR 2.6 billion, with a strong contribution from all businesses. The drivers will be the valuable production growth resulting in additional $1 cash flow per barrel to $20.5 per barrel, the retained Gas and Power customer base expansion, further business integration in Midstream, as well as the growing contribution from the repositioned refinery capacity. Organic free cash flow at 2019 scenario will continue to grow at a robust pace with an average CAGR of 17%.
As a result, the cash neutrality to cover working capital, CapEx, and dividends will improve from $55 per barrel in 2019 to $50 per barrel by the end of the plan period, demonstrating the increasing resilience of our business model and the support in the progressive shareholder remuneration. Talking about the remuneration policy, the progress we have made in enhancing our portfolio has been remarkable, as reflected in our 2018 figures. Looking ahead, we are targeting a further material as well as sustainable growth that will drive the margin expansion in all businesses, combined with a stronger balance sheet. On this basis, we are pleased to announce an increase in our 2019 dividend by 3.6% to EUR 0.86 share, in line with our commitment to a progressive remuneration policy. In addition, we will start a four-year buyback program, envisaging in 2019 a capital allocation of EUR 400 million.
In the following three years, assuming a leverage steadily below 20%, the annual capital allocation will amount either to EUR 400 million in a $60-$65 Brent scenario, or EUR 800 million in a scenario above $65. Now to conclude, some detail about the IFRS 16 impact. You know that this new accounting principle is effective from 1st January 2019. The main impact on the new standard in 2019 will be the accounting of the opening lease liability of around EUR 6 billion, that will imply a leverage increase of around 10 percentage points, an improvement of around EUR 1 billion of free cash flow, reflecting the classification of the principal portion of the lease payments as financing cash flow, and an EBITDA increase of around EUR 0.3 billion as a result of the reclassification of interest component of the lease cost as interest expenses.
The adoption of the new accounting standard may impact some major performance disclosed in this presentation, such as the leverage, the cash neutrality, and the operating cost per barrel. To facilitate the full comprehension of such broad changes, in 2019, companies reporting selected main metrics, we will disclose also excluding the effect of the IFRS 16. In particular, from 2019 on, we will detail the lease liabilities accounted for in the financial debt in order to measure the leverage as it was before. That remains the reference for our remuneration policy. Thank you very much. Thank you, Massimo. Now our ambition for the next decade. In Upstream, we will continue to grow organically and diversify our geographical footprint through a greater presence in Middle East, in East Africa, and Asia.
We will leverage our core competencies in exploration and development to maintain a project breakeven well below $30 per barrel. In a lower carbon world, natural gas must play a greater role. By 2030, up to 60% of our production will be gas. In LNG, we will more than double our global LNG versus 2018, leveraging our integrated model with Upstream. We are also well positioned to capture share in the European retail market, where we will continue to be a relevant player. In Downstream, we will continue to improve overall asset efficiency, lowering refining breakeven to less than $1.5 per barrel through a further balancing of our capacity. In refines, we aim to increase our position in renewable chemistry.
In Renewable, we will focus on the development of new solar and wind capacity, with a target of more than 10 gigawatts, and we will expand our biofuel capacity, focusing on the second and third-generation feedstocks. Decarbonization is structurally embedded in our overall strategy and ambitions. Okay. Thank you. Good afternoon. We are now ready to start with the Q&A, please raise your hand and we'll give you the word. Pavel?
Thank you very much. I wanted to start on the upstream, please, with this significant visibility here out to 2025, a good seven years of production growth. When I look at page 10 and I look at your little exhibit, at least in 2019 up to 2022, the gray shaded area, at least if I'm reading that correctly, still looks like it's at least a 10% decline rate coming through the base portfolio, really relies on executing the ramp-up of this new pipeline. I just wanted to know, also in the press release, you speak about enforcing the long plateau, long pipeline projects for the future.
My question is there a period between 2019 and 2022 where the base is pulling back a little bit harder, before you layer in those longer term, long plateau projects in terms of risk here, in terms of the production growth numbers? Secondly, just linked to that, Angola Block 15/06, significant resource. You speak a lot about fast track and how we should expect that to be fast tracked as well. I guess some of your competitors are moving back into the country. This is properly deep water, perhaps a little bit more challenging to execute a fast track program. Do you see that as a risk as you think about that country? Thank you.
Thank you. I start from the last questions. Angola, when we talk about fast tracking Angola, it's something that we already achieved because the East Hub and West Hub that are in the deeper shore have been executing the 3.6 here. That is half all the time to market on the deeper shore. That has been executed in the last four or five years. The time to market from the discovery to the production was for me really fast. Something that has already been done in this country. The new discoveries, how we are going to treat the new discovery, we are going to treat the first two discoveries that as well, but they are going to be tied in to the existing hubs.
Just in the first early production, because we have to test, and that means that they can put in production less than three years. In one, actually a couple of years, we can put in production also less. The big discovery as well, we are going to have an early production because our safe approach to create the cash flow in the same PSC, so during the monetization with the others, we can cover immediately investment. I think that for the third one, we have to go for a third hub. We already done and we can manage that because there are new companies in the country that our time to market is going worse. I think that for that, we are pretty sure, and that is new.
It clearly is so new that is not in this three-year plan, because they are discoveries that we made recently. The decline rate of our E&P goes in the 5%, and the 5% that we get also with our production optimization on the existing fields. That is stable. There is no reduction. We confirm the 3.5%. The good news is that we are going to put in production, we are identifying four based, I think, on the 2P reserves. Remember that in the past three years also, the contingents we said that exploration, that we can call it primer steps.
Instead of being tested, we have really internalized the process and we are ready in the process, so we are really running for the 3.5% on the 2025, because there we have big projects, like Nené and the other projects that will be really part also of the plan. What also in this case, we talk about 3P reserves. We've never been so robust in term of our growth because we have in our hands really sure ourselves. There is no up and down, and the decline rate is 5%. Chris, Mike.
Thank you for taking my questions. Chris Jamart from JP Morgan. A couple of questions. First of all, your capital framework, when I think about the buyback targets that you've laid out, and the trends that's linked into gearing and oil price. I just want to be clear, is this regardless of whether oil goes below EUR 60, will you continue that floor buyback? In regards to gearing, if you see an opportunity and re-gear again, will that mean the buyback gets recalibrated? Because I just want to understand the relationship between the gearing, the oil price, and your scale of the quantum of buyback. The second question is regarding your GP Adnoc deal, we didn't really talk about that in this presentation at length, but we'd love to.
The logic, across the Middle East, we're seeing Aramco and others do a significant export capacity and refining that comes linked into the countries they're buying from them. What's the logic in terms of through cycle to now go around additional capacity through your understanding from the upstream, from understanding from a sort of full value chain perspective? Is this sort of typical cycle investing regarding potential late cycle margin?
Nothing more answer about Abu and stuff and the R&M in upstream. In term of buyback, I get the policy is clear. Below $60, there will not be any buyback. The difference between the $55 cash break even and $ 60 will be devoted to incremental dividend and debt reduction. Buyback will start above $ 60 or from $ 60 on. The attempt is to stay between the range that we are giving. EUR 400 million between $ 60 and $ 65, and above $ 65 and EUR 800 million. This is the way link the amount, the oil price needs to give a room to the flexibility that is underpinned in the buyback. Our purpose is to distribute back cash to shareholder depending on the amount of the excess cash.
The best, I would say, indicator to figure out the available free cash flow will be the oil price. That's the logic. In term of, I would say, priority in the allocation of the additional cash, I would say a good example is what we are doing in 2019. What I expect in 2019, assuming a $52 per barrel, as we are assuming in our forecast, the leverage, we are talking about leverage not gearing, is assumed to be slightly higher than 20%. Our visibility looking forward is for a leverage below 20%. Notwithstanding the acquisition of the 20% of Ruwais that Claudio is going to talk about in one second, we are taking the promise that we are in the position to distribute this additional cash flow.
We are keeping well in mind the balance between maybe a future growth that could be even not organic versus the remuneration of our shareholders.
Talking about the entry in our recent entry into the UAE and Arab for 6 years. That is first time that we are in Abu Dhabi, in Bahrain, Oman, Qatar. Clearly the first reason is the quality of the assets. When we talk about quality of the asset, we talk about the upstream and downstream. We are always stable because we are in a producing field. We had to develop, and that is a very strong point because Abu Dhabi, in the new strategic plan, decide to develop gas. They didn't before. We want to meet our position and also to export. We became the technical in the joint venture, the technical leader of all the gas development in the offshore. We do development itself, but we have also the exploration.
All the exploration block offshore around these development that we are going to perform. We have other explorations. Our view was, first of all, we had the need to have some quality assets in the refinery that could be seen as a assured way also to rebalance the upstream when the price is low, but also because our strategy, and one of the key word that we use, not now, but since long time, is for a long time, integration. In this case, we reached the target. We have a full integration from exploration to development to the refinery and marketing, because we have also constituted a joint venture for the marketing. That is the way to create value. We don't want to
buying something there, buying something there. No, we want to create a critical mass. We want good quality assets. We want to be along the chain. That clearly is giving a strong contribution also on average to our refineries. From our point of view, that was possible also because we made some proposal on our technology, and because we have a complex refinery in Italy. We had to really optimize all our refinery systems, and that's all the technology and patents that we developed in Italy to reach out the machine in the country where there is no oil and gas, or very poor. There we can apply and can give a new upside in terms of value to the refinery, to the extension, the future extension. That is the reason why we're doing that.
On top of what Claudio is saying, an additional plus, the Ruwais refineries, brand new, but already in production. For us, looking for the rebalancing, immediate rebalancing of our portfolio, that is a plus. We are getting some dividend from now, from 2019 on, and the investment will be self-financed investment. It's really resilient in terms of cost, very well located in terms of geography towards the markets of reference, and capable to give this rebalance in our portfolio immediately. Jason. Jason, go ahead and talk now.
Thank you. Firstly, thank you for your hospitality over the last couple of days and this morning as well. It's Jason Kenney from Santander. I just have the one question really. It's about profitability, and I want to know when a return on capital employed is going to be ahead of WACC.
The return on capital employed has been higher than the weighted average cost of capital in 2018, when we counted $72 per barrel. We expect it to be at $52 at the same level. We are talking about a weighted average cost of capital slightly higher than 7%. We expect it to be higher than 10% in 2021 and 2022. Among this, E&P will be always above the weighted average cost of capital that refer to the E&P business, which is 7.7%, 7.6%. Michele, do you agree?
Thank you. I had two questions on your sector leading target to reduce net carbon emissions from upstream to zero by 2030. First, on the carbon capture of 30 MTPA of CO2, I was wondering how you think of reforestation versus carbon capture and storage there, and what costs per ton of CO2 you think you can achieve there. Thinking about your biofuel strategy, you transformed two refineries which were loss-making, Venice and Gela, into profit-making biofuel refineries. I was wondering how much more do you think you can scale up that business in the longer term beyond the one MTPA, and how complex are the logistics to get all of the feedstock in place, particularly when it comes from waste? Thank you.
Thank you. The first one was related to the carbon, the natural sink sequestration. The natural sink versus CCS. Clearly, natural sink is less expensive, much less expensive. We range in cost of about between 11 and 16 on average, because that is the cost of the recovery investment. Investment are not so much, $11 per ton. It's less heavy and less expensive than the CCUS. Clearly, we are working also on the CCUS in a different way, CCS and CCUS. I think that during the visit this morning for the new people that had the opportunity, there are different kind of possible sequestration using technology. When you talk about power plant, you're talking about your refinery or your chemical plant. You need also CCUS. You cannot recycle everything with the sourcing.
Really, sourcing for us is more than acquired credit because you can buy. It's a little bit more expensive sometimes or less expensive, depends. It really is impacting our communities. We are doing and we are going to do in Africa. In the country where we operate. Generally speaking, in Africa, because we do also in other country like Zambia, like South Africa, we are not really in operation. We are not in Ghana. We have projects that are impacting the society. It's really creating a lot of jobs. It's creating a different kind of diversification, which are the culture, but also this is a diversification. The model is quite straight because we are working with developers. We are not yet a developer in this part.
As a developer in small areas, no, big areas. Small compared to what we are using now in Ghana. We want to work there because we have a lot of community. We also wait too, so we engage. They are in commitment to buy the credits, and then we give back to the community some percentage that can go from 10% to 40% related to the gains that you make from the credit you buy. It's really good for the environment, it's really good for the communities, and clearly for us good because it's a way to offset our residual upstream Scope 1 emissions. The other question about how we can expand these business. Clearly, this business is going to be quite big. We can cover all internal consumption and maybe also exports.
The first point is really the logistics, not the logistics to have the palm oil, because it's quite complicated and it's been some months. We are going to another direction because we want to use a second generation. We are using at least 20%, 25% second generation. Our aim is to, because the technology that we have, that is our own technology, allow us to use 100%, and Gela is going to use 100% the second and possible third generations. We want to rapidly, first of all, in these refineries, to stop using palm oil. In the future, if you want to talk expansion will be different scale, because I think that you, Somebody, I think you saw the waste-to-fuel technology. That is smaller, the scale is smaller. We have already a plant in Sicily.
That is much better to cover the local issue about waste material and biomass and so waste material that is so organic. The future will be a smaller scale. Using our technology, we are working with Café in Italy in smaller scale to produce oil. Oil, or also feedstock for our refineries. This waste-to-fuel is very interesting also for abroad because the production is about 30%, 35% oil, and we have 65% of water. From the organic stream. You can imagine in other parts of the world where they need water for agriculture, then there is some CO2 there to use for sequestration, for example, in Algeria. I think that the development of the technology is so fast, and for that reason, we talk about employment, job employment of our R&D, that the development of this part will be completely different.
We are going to make plants where we have waste, to cut logistics, also to improve the agency and improve the reducing these CO2 emissions. Hassan, Jon.
Hassan Dawood from JP Morgan. I believe you've seen a reduction in the breakeven cost for projects in the upstream towards $25 per barrel. I was wondering how much of that is driven by numerator, so through the CapEx intensity, and how much is driven by just going after bigger projects with larger resources. That is first 1. The second 1 is on the buyback. I was wondering if the EUR 400 is going to be implemented maybe in the second half of this year, and then as you look at 2019, when do you decide the buyback? Is it on a quarter by quarter basis, or six months by six months, or if you can look at how you're going to?
We talk about the breakevens first because it is the 1 we can pay the buyback. The buyback, the breakeven is really why, because it's a new, I think, kind of model. With this, because we are more efficient, and also the quality of the project, and also the phase of the project. The overall package, phasing the project, reducing more efficient cost, working with a very good kind of market. The new projects are also a project that on [rigorsers] and following our model, it are close to different facilities. That helps a lot because they are big projects that you are able to be more efficient in your CapEx. Clearly, we talk about giant projects close to different facilities, safe projects. All this is creating this good result in term of breakeven.
The buyback is we have to propose to general assembly and then I think that for EUR 400 million, that is this year. We start immediately. That can be in July, June, or August. We don't know that there. We start using the model the maximum strength we use. For to pay every quarter or six months, I don't think that change a lot. At the end of the year, I don't know, Massimo can answer that.
Exactly what Claudio said. What I could add is the plan will be put in place as soon as possible in order to avoid any kind of interference with the market. Starting from 2019, we will start the buyback immediately after the general assembly, and from 2021, we will start at the beginning of the year. I would say the reference for the amount of buyback to be applied along the year will be our scenario. The price we assume in our scenario will be the driver for the amount of share to be bought back that year. Jon?
Hi, it's Jon Rigby from UBS. Can I ask a couple questions on LNG? You referenced the volume improvement or expansion that was involved, or I think you indicated in Gas & Power, actually. Can you just talk a little bit more, articulate a little bit more, what you're going to do with those volumes, what kind of EBIT impact you're expecting from them, and how you're using those volumes to generate EBIT in Gas & Power? The second question, just a point of clarification on your Scope 1 emissions in the upstream. You talk about Scope 1 only. Do the LNG processing activities fall into that, or is that sat in Scope 2? Thirdly, just a point of clarification for Massimo. I think you indicate there's a EUR 0.3 billion, sorry, EBIT benefit from IFRS 16.
Where does that fall in the guidance on the EBIT guidance that you've given on a segmental basis? Thanks.
Okay, for the LNG, clearly the LNG, it became a very strong tool for our equity in gas because we discover a lot of gas, which will give a strong flexibility to our upstream. We have to look at it clearly from a representation point of view to the separator, but we have to look at the flexibility that the LNG, a very strong LNG, gives to our upstream because they are really working together. Last year was very positive because in Nigeria, for example, we have been able to increase production and use LNG also for spot cargo. They gave a big possibility. As I said during the presentation, the EBIT growth will be long term because it's contracted LNG, which is based on our equity. Our equity is strong now in, we can say, Nigeria, in Angola, in Indonesia.
We have to restart with Damietta, and we'll be very strong with the Coral and with the two trains that we are developing in Mamba in onshore. Clearly, it's the long term. The impact will be strong, but just related to the commercial part, because we don't see all the upstream. I don't have now the figures for the long term, but we talk about very interesting figures clearly after this plan, when Mamba and Coral and the other additional development for gas in Egypt, and we can start using Damietta. The other question was Scope 1. With Scope 1, I would say that is a major first step, and that is upstream. Now we are working. We are not ready yet.
Just to reach this, we worked three years because it's clearly a message directly from the top, but then it involves a lot, because we have to build the model, and we have to work to be sure to take a so important commitment. We are working on to finalize the Scope 1 for all our businesses. Clearly, we are also working on Scope 2. We do not have the figure, but we have about 42-40 million tons per year for our Scope 1. When you look at the Scope 3, we have 250 million tons. The first step is to upstream, then the rest of the business, Scope 1, and then that we are already working on Scope 3. That implies different things. It implies also policies and implies the market trend and implies our also products.
It's more complicated, but we are very determined to reach this target. First of all, in order to ensure that it is absolutely clear, all the numbers that is being disclosed this morning refer to the number before the implementation of the IFRS 16. The final slide gives you the reference about the magnitude of the impact. That said, all along 2019, we will always present to you the double view before and after the IFRS 16 in order to allow you to better understand the impact, that is a significant impact. For example, when we say that the free cash flow will be EUR 1 billion higher, means more or less EUR 5 in terms of cash royalty for us. It means that the most important metrics will change dramatically.
As far as the EBIT that you mentioned, the 0.3, due to the fact that the advantage in terms of EBIT relating the, I would say, reclassification of financial interest, definitely this advantage will fall in the field of the upstream. That technically is the most important user of our debt.
The first question is on the dual exploration strategy. It looks like a lot of the activity that is planned for 2019 is actually more near field exploration. Should we think about the strategy then in terms of generating early cash flow is more early production systems tied back to infrastructure, like with the G∙row, rather than equity divestment of exploration success? The second question is on ADNOC Refining and the dividend policy. I believe that you said at the time of the announcement that the dividend would be pretty attractive, around 10% or so on investment, but that it would be over the medium term.
I guess my question is, does the free cash flow that you've laid out for R&M include a dividend of ADNOC Refining in the latter part, and would that potentially be interrupted if there was a decision to further expand their Ruwais facility?
Okay. Also on the dual exploration, Massimo can talk about the dual issues. The dual exploration are really continuing. We are pretty solid, continue to have been discovered. Recently, we used dual exploration internal swaps indirectly into investment for the future. It is continuing an active tool, an active mechanism, because now we use the dual exploration when we're in the downturn, and we need to reinforce also our cash flow. In this case, we prefer to use a swap to get asset into work for our diversification. That will be the way. The near field exploration is really not new. It is not just for today, this year, last year. We have been successful because we use this kind of more the near field exploration.
We go where we have facilities, but two different tools, especially in the pre-salt, on different kind of traps, stratigraphic traps, subsalt. We can discover something that the other didn't discover, but in very mature areas. We have contract non-situation, we have facility, we can drill down. We are in this phase. We are going to continue, and that is more focused on swapping than cashing in.
The number that we have shown as far as R&M do include the contribution that we expect from ADNOC Refining. Our 20% of ADNOC Refining. You correctly mentioned the expectation in the range of 10% as a medium. Technically, we expect it on target in terms of capacity. Even now, as I said, the advantage to getting into such a huge asset that's already producing, already running, is to have some cash flow anyway. In the numbers I said, we already embedded such a contribution, that in the first year is not meaningless. We are talking about something in the range of EUR 200 million each year. Growing over EUR 300 million by 2023, 2024, when the configuration of the current capacity will reach the scope that now we are envisaging, we are working for. This additional activity will be self-financed.
If there would be an additional growth expected, technically, we will evaluate it. If we decide that this additional growth is valuable, we'll be happy to give up some cash back to be reinvested in such an initiative, because we believe that this refinery is a very nice, very good investment to stay in.
Thomas, and then Chris.
Thank you for the presentation. Thomas Adolff from Credit Suisse. I've got two questions, please. Firstly, on organic versus inorganic CapEx. In this presentation, you talked about organic growth, you've been very busy doing inorganic things in the recent past. I wonder what role will M&A play going forward? Are there any particular gaps you still want to fill? Do you want to expand further into the Middle East, such as LNG? The second question is just on capital intensity in the upstream. By 2024, 2025, your upstream production will be about 25% higher than it is in 2018. You still guide to a CapEx that is relatively flat over the four-year plan period. Perhaps you can talk about capital efficiency or any other things you assume in that. Thank you.
Thank you. You said that recently we have been very active. Recently, in the last 10 years, we did just raise. We are not so active in kind of M&A. We talk just about organic growth because we just aim at growing organically. That is all we will talk, really, opportunistic on asset. Maybe that it is not really because we have so many reserves, so many 3P reserves, and so many discoveries that we have to be focused what we have. If you look at the cost of our exploration, now we put $1.8, but the average of the last five, six years is less than $1 per barrel. If we have to buy something, it is always more expensive. Clearly, we are organic. I think that we are going to join in if there is some possible asset that we like.
We have to think that we want to keep the right balance between our dividend and buyback system, so that our investor and diversification or asset to farming. We have a clear priority. We do not need to buy something. We gave a clear indication about our remuneration policy, and that is clear in front of us, and we want really to respect. When we start something, we absolutely respect what we promise and what we say. You do not have to be worried about some competitions or any growth, because we do not need it. For the CapEx. The CapEx, you look at the year, but our cycle is four or five years. Our growth, the growth that we are implementing now, started maybe three, four, five years ago. It is not really correct. We try to be really flat.
That is very important to respect our free cash flow in the winter. We try also to reduce the inactive capital. I remember that six, seven years ago, we had 35%-40% of inactive capital. Now we are in the range of 15%-20%. That is intrinsic, because the cycle is very long, but we try really to reduce the inactive capital in the year. How you can do that is with the time to market. Angola is an example. Jan Mayen is another example. Algeria is an example. If you are able to reduce, it could be your time to market, you do not have inactive capital. That is another side. That is really another side of the map that our structure made with the aim to protect the future flow, reduce the inactive capital, and optimize all the assets of our investment. Thanks.
Thank you very much. Chris Cooper from Bank of America. I have got a few questions on Vår Energi. The first one is if you could talk us through a little bit the rationale behind the merger, perhaps the role that you expect Vår Energi to take within the Eni plan and future. I am hopefully right that you have accessed some growth in Norway thanks to this transaction. I wonder whether you can give us a little bit more detail about how that growth is funded, how much free cash flow that new company is continuing to create in order to fund also the Eni dividend ultimately. Then, related to that, just quickly, I saw on one of your slides that you referenced a proportional consolidation in the CFFO here in your guidance of Vår Energi.
I just wanted to double check whether that applies to CapEx production, et cetera, how you've treated that.
Okay, Massimo, if you want to answer, because it's more on dividend and the self-financing. The rationale, as you said, is to get access to additional growth in Norway. Norway is a place in which there is still a significant exploration upside.
Merging the portfolio of companies now allow us to have a very well spread portfolio from the North, the Arctic, to the South. Even in term of operation, the situation is much better. The organization in place now is very solid, so capable to run the activity in Norway by their own. Definitely, we are looking at what they are doing, but the contacts are constant. Merging the portfolio is allowing us to have a larger cash flow. For example, Fenja will reach the FID this year, and will come in production very soon. This additional cash flow is allowing us to have, I would say, an additional comfort that we said, I mean, amounts in the range of more or less $2 a barrel in term of cash neutrality. This to give you the dimension of the contribution.
In term of representation, some numbers we have shown this morning include a pro forma contribution from Vår Energi. Because of the, I would say, the comparison between future numbers versus previous numbers. For example, the dollar per barrel we have shown growing from 18.5, 2018, that include the cash flow from operation from the Norwegian activity, while in 2019, 2022, do not include the contribution. What we have done, we are including pro forma, the contribution from Vår Energi also in 2019 and 2022. This is the adjustment we have made in our numbers. While all the other numbers, for example, the refining margin assumption, will include the dividend that we expect from Vår Energi. On this regard, nothing change.
Okay, the last one, Massimo, and then
Massimo Bonisoli from Equita. Thank you for the presentation. Two question on the downstream. One on the refining margin assumption, which increased by EUR 0.50 per barrel over 2020, 2021. How much is coming from the IMO 2020 changing regulation, and how much from maybe the inclusion of ADNOC in the new structure? The second question on Versalis. If I remember correctly, you earlier mentioned EUR 270 million EBIT assumed by the end of the plan for Versalis. How much is coming from a scenario recovery, and how much from self-help measures? Thank you.
Okay. Give the floor to the R&M CEO and then to the CEO of Versalis.
The increase of margin that you are seeing in the 2020, 2021 is due to IMO. Is due to IMO because we expect that the introduction of this new specification for bunker oil, we will have a depreciation of high sulfur crudes and an increase of appreciation of distillate, main gas oil. This means an increase for at least a couple of years of the margins. The contribution of ADNOC will be for the breakeven. ADNOC will help us to reduce the breakeven below the $3.
For the Versalis side, the results are mainly coming from the scenario, about EUR 200 million, the remaining is for our own agenda and actions. As you know, increasing resilience of Versalis is the mission that we have. We are doing that in a difficult situation because the market didn't help us over the last six months. We are doing that with existing assets as well. It's something that we consider to have done significant improvement from the past, where we were losing EUR 400 million or EUR 500 million. Now we are swinging between breakeven and EUR 200 million, EUR 300 million positive. We do our best to continue to work on integration, efficiency, changing of portfolio, and renewable materials as well. Thank you.
Okay, thanks. Thank you to all. We will return after 3:00 P.M. Sorry, after 2:00 P.M. for the Q&A with the CEOs, we leave the room for the press conference.
Okay. Thank you.
Thank you very much.
Thank you.