Good afternoon, ladies and gentlemen, and welcome to our strategy presentation. This is the first time that we discuss our strategy after we transformed our business profile and balance sheet through the divestments of Snam and Galp. Today, I would like to give you an update on the growth and returns which our new Eni is positioned to deliver. E&P is the main driver of our growth. As Claudio will detail later today, we have a wave of projects coming on stream over the next 24 months. This, coupled with our track record of exceptional exploration success, means we are poised to deliver a decade of strong growth. Our production will grow to around 2.5 million barrels per day, through 1.3 million new barrels, which are well-placed on the cost curve and will deliver robust returns.
In Gas & Power, we are positioning ourselves to make sustainable profits even in a half-price world through accelerated contract renegotiation, a continued focus on solid segments like retail and LNG, and a revolution in the way we serve our larger wholesale customers. Marco Alverà, who is leading the effort on some of these fronts, will give you some more color during the course of the afternoon. For different reasons, R&M and our chemical business, Versalis, have been a significant drag on our overall results. Cost cuts, capacity rationalization, and in Versalis, a refocusing on profitable segments, means we are expecting significant improvements for both businesses during the plan period, even with no help from the scenario. With regards to capital allocation and the future shape of our balance sheet, 2012, we have delivered a financial improvement of over EUR 19 billion through disposals.
We will continue to be pragmatic about the way we manage our portfolio of businesses and assets in 2013 and beyond. Our objective is to maximize value for shareholders from non-core assets and from the optimization of the huge E&P portfolio that we have accumulated through exploration, something we have made a good start on with the CNPC transaction announced today. With regards to capital allocation and the future shape of our balance sheet, the new Eni is more exposed to E&P, a trend which we'll continue to see throughout the plan period as we will focus the vast majority of our investment on this business. Also means much higher returns, but also means greater volatility and much greater political and operational risk than the regulated business we are exiting.
This is why we are fully focused on managing these risks through a strong balance sheet, strict discipline on project delivery, and diversification of the different risks we take. Take North Africa as an example. Legacy countries, Egypt, Libya, and Algeria, form a significant part of our business, accounting for almost a quarter of E&P capital employed. The impact on Eni of the region's troublesome transition have been managed. Our strength in exploration has yielded valuable near-field discoveries that already contribute 20,000 barrels per day. Made good progress on delivering growth projects with the startup of MLE a few weeks ago, El Merk a few days ago, and CAFC later this month.
Speaking about Libya, we have quickly restarted and ramped up production after the 2011 revolution. Of course, the situation remains complex, as last week's temporary interruption of production and gas export shows. However, the situation has now normalized, and we are reassured by Libya's commitments to the integrity and full functioning of oil and gas facilities, including the crucial Mellitah hub, a position which the Prime Minister reiterated to us when we met him on Monday, last Monday. Looking forwards, our growth in other regions of the world will reduce our exposure to North Africa, both in terms of capital employed and production, which will go from one-third today to around 15% of the total over the next decade. Meanwhile, our refocusing on E&P comes at a time when the division's growth opportunities have been multiplied.
Over the past five years, we have discovered around 7.5 billion BOE of new resources, more than double our cumulative production of 3.2 billion oil barrels. This is not all Mozambique. Even excluding Mozambique, so if we exclude the big Mozambique discovery, 2012 would have been in line with our four-year track record of around 1 billion BOE, well above average annual production of around 640 million BOE. This remarkable result sets the foundation for industry-leading growth. Over the next four years, we will grow our production by above 4% a year on average, with above trends in 2014 and 2015 as Kashagan ramps up, and other major projects such as Goliat, Perla, and the West Hub in Angola start up. Our focus is to deliver this growth on time and on budget. Our visibility is supported by the sanctioning process.
We have already taken FID on 65% of this new production to 2016, and we raised this proportion to 90% by the end of this year, 2013. 80% of this new production comes from projects which are onshore or in shallow waters. Looking further ahead, recent discoveries, including Mozambique, will support growth of more than 3% a year on average to 2022. This new production will deliver strong returns under almost any oil price scenario. The reason being that our resources come from organic exploration discoveries with low development costs, thanks to our largely conventional onshore and shallow water giant discoveries and projects. To this, we need to add operating costs, which will be higher for new production, driven by complex major projects such as Kashagan, Goliat, and West Hub in Angola, compared to our bedrock of legacy production.
In any case, we are looking at overall cost per barrel, exploration, CapEx, and OpEx, so these three items, well below $30 for new production, before royalties and taxes, which will, of course, depend on price. That means returns on new projects will be resilient even if the oil price falls, and very strong if the oil price stays at current high levels. Turning now to Gas & Power. Over the last few years, this business has been affected by a number of crosswinds. First, we had a rapidly rising oil price. We are not unhappy with high oil prices, which have added billions to our Eni results over the last three years.
Looking at the world from the perspective of Gas & Power, which buys most of its gas through oil-linked long-term contracts, these high oil prices have resulted in increasing supply costs, only partially absorbed by the supply renegotiation we have closed to date. Second, and most important, we have seen demand collapse. In the EU, we have lost 15% of consumption, or over 80 billion cubic meters between 2008 and 2012, and supply has not responded to this, with increased spot availability and the rigidity of the take-or-pay contract. The result is that selling prices have come under significant pressures. The combination of these two trends means that when we buy gas on the basis of the existing long-term oil link contracts and sell it at European spot prices, we lose money.
This is exactly what has happened to our European wholesale business, which would have made a significant loss in 2012 if we normalize results for one-off items. Overall results were supported by the oil-linked LNG and retail segments, and our stable international transportation and distribution businesses, with a modest contribution despite the poor scenario from our efficient, integrated, and cogenerative power activities. Looking ahead to 2013 and 2014, we are expecting even more pressure on margins, especially in Italy, where new contracts have quickly converged with the European hub. In this context, the context we live today and we expect to live tomorrow, our number 1 priority is to negotiate with our suppliers. At the moment, we are in negotiation for around 80% of our gas. With the aim of bringing purchase prices down to at least have prices less costs.
On that basis, what is the potential profitability of our Gas & Power division? Which means, if we achieve that, what will be the forecast of the profitability of our Gas & Power division? Let's look at this segment by segment. First, international transport and semi-regulated activities. This business includes international pipelines such as GreenStream, Blue Stream, and local distribution assets, and generates stable results. Second, retail Gas & Power sales will continue to be profitable business. We are growing in Italy and in Europe, and target an increase of 3 million new clients to reach a total of 14 million by 2016. Our third business is wholesale, selling Gas & Power to large industrial clients.
While these customers are extremely price-sensitive, we expect to make reasonable margins by selling structured products with flexibility on volumes and different ways to manage pricing, something which is made possible by the integration of this segment of Gas & Power with our trading arm. Fourth, LNG. This has been a strong contributor to our results, something we expect to continue, even if LNG prices in the different regions of the world will gradually start to converge. Add everything up together, and once Europe have stabilized and the renegotiation effect through our numbers, we expect Gas & Power to make something in the region of EUR 1.5 billion of adjusted pro forma EBITDA.
In this context of a well-supplied market, where customers do not price in the value of our supply security and flexibility, if the market tightened through demand growth or supply shocks, our diversified and flexible portfolio would again become a competitive advantage with benefits to the overall profitability of our Gas & Power business. Turning now to R&M. This is a challenged business, but one which has made real progress in 2012, through a combination of an improved scenario and self-help measures. With regard to the scenario, we believe there is some room for cautious optimism. In the face of dramatic demand declines, around 10% in Italy, decline in petroleum products unheard of before, decline of 10%, and 3% in Europe, capacity rationalization is starting to happen. From 2009 to now, 11 refineries shut down in Europe for a total capacity of 1.4 million barrel a day.
A further 15 refineries could potentially close in the coming years. That said, our plan targets a return to profitability even without assuming any further scenario improvement. Our efforts are on track. Last year, we announced a EUR 550 million efficiency and optimization program, the vast majority of which is refining. Over the course of 2012, we have delivered around EUR 150 million of recurring efficiency, largely energy savings, labor, and logistic cost reductions. Looking forward, we'll continue the program we announced for the remaining EUR 400 million, mainly through the startup of EST and further savings. On top of that, we have identified additional improvements from the conversion of Venice into a green refinery, cutting down 10% of our overall refining capacity and exploiting our proprietary Ecofining technology. We also expect marketing results to improve given the impact of last summer's extra-large discount.
Overall, at the same scenario as 2012, we expect R&M to break even by 2014 and make something in the region of EUR 200 million of EBIT in 2016, with further upside from the potential improvement in benchmark refining margins. Lastly, an update on Versalis. 2012 was a disaster in the European petrochemical sector in which we operate. We had the worst scenario since 2000, with high naphtha feedstock prices, which we could not pass on to our ethylene and polyethylene customers because of weak demand and competition from much cheaper Middle East producers. As a result, we posted a heavy loss. Given the deterioration in the market, we have increased our efforts on the major turnaround plan launched last year. The old plan targeted over EUR 400 million of incremental EBIT by 2015 at the constant scenario.
As a result of cost cut, the refocusing of the portfolio away from loss-making basic chemical and towards specialties, and establishment of a foothold in fast-growing Asian markets. Our new plan targets around EUR 500 million of extra EBIT by 2016, at constant scenario, with more incisive efforts on rationalizations. This on top of the EUR 60 million of savings we have already achieved, largely through the closure of the Porto Torres plant. We have also laid the foundation for our portfolio refocusing with agreements in the field of biochemicals and with major South Korean and Malaysian petrochemical joint ventures.
We expect to make significant progress in 2013, driven by the closure of the polyethylene plant and the reduction of the steam cracker capacity, both in Priolo, the startup of the first two green chemicals plant in Porto Torres, and to reach breakeven by the end of the plan period, even at the terrible 2012 scenario. At the end of the turnaround period, 2017/2018, we expect additional EBIT of about EUR 300 million, including the pro forma contribution of our new joint ventures. This turnaround represents a major change for us. Daniele Ferrari, who is here, will be happy to answer any detailed questions you might have, both today and at the specific chemicals seminars we are organizing here in London for April 18. Now I will hand you over to Claudio Descalzi for a more in-depth look at the E&P strategy.
Thank you, Paolo. Good afternoon, ladies and gentlemen. Today, I will take you through the evolution of our upstream business at what is a very exciting time for us. The key growth driver for the next 10 years are all in place, and we are making good progress towards rapid and valuable production growth. Now let me take you through the five drivers of our strategy and how they translate into action and targets. First, our approach. Everything we do is governed by the Eni model, our distinctive culture, which means operational excellence, continuous improvement, and mutually beneficial development. Second, rapid conversion of our 34 billion barrels of resources into production with an accelerating time to market. Third, delivering on our robust portfolio of 120 development projects, which will add around 1.3 million barrels per day of production over the next 10 years. Fourth, exploration.
Starting from our very strong acreage base of about 300,000 square kilometers, we are constantly rejuvenating our portfolio to include new material initiatives in our core areas and in emerging markets. Fifth, leveraging on our cost-efficient structure to ensure resilient and robust returns. Let's take a look at each of these in turn. First, the Eni model. As you know, Eni has a very distinctive approach, which underpins all our actions and supports our capacity to access new resources. A strong HSE performance is a core part of this approach. The total recordable injury rate in 2012 was the best ever and 50% lower than the average of the previous five years. On drilling, despite the increasing number of operating wells, we have recorded no blowouts, zero blowouts, in the last nine years. On sustainability, last year, we are proud to have achieved record results on gas flaring.
Our aim is to reach zero flaring by 2017, completing our major projects on North Africa and West Africa. As we are working on this objective, we will continue to turn gas flaring into a development opportunity. Today, our power station in Nigeria and Congo accounts for a good portion of the domestic electricity produced, and this solution is in line with our focus on local development through energy, but also agriculture, social, and development projects. This distinctive approach is the foundation of our growth strategy. Growth will come from turning the huge amount of resources we found into reserves and production, with an accelerating time to market. As Paolo mentioned, 2012 was an exceptional year for exploration, with reserve replacement exceeding the positive trend of the recent past. We discovered 3.6 billion barrels of resources with a unit exploration cost of EUR 0.60 per barrel.
In addition to Mozambique, we made major oil discoveries in the Barents Sea, in Ghana, Congo, and Angola. These represent about one billion barrels of new resources. As a result, overall resources are up by 7.5% year-on-year. Most importantly, we have increased the 3P and contingent resources by more than 25%, proof of our progress in turning resources to reserves. This is a result of our strategy of selecting material, high risk, high reward opportunities, and accelerating appraisal campaigns. Our new discoveries have to be transformed into production in a timely and efficient manner. This is our priority. The first step is to sanction projects quickly, which will lead to an average organic reserve replacement ratio of more than 130% over the next four years at $90 flat.
This means that we will be able to put 90% of our recent discoveries into production in less than eight years. In addition to major projects, we will benefit from a stream of fast-track opportunities. For example, in Egypt and in Pakistan, we started up fields within one year of discovery that account for 120 million barrels of reserves, and in the Egyptian Western Desert, we ramped up to 20,000 barrels per day only nine months after discovery. This focus on fast-tracking our projects translates into overall production objectives. Our growth to 2016 will be more than 4% a year on average, at a price level of $90 per barrel flat. This target includes contingency of over 200,000 barrels per day. Our growth will be resilient to higher oil price. At $120 per barrel, we would deliver growth of more than 3.5% a year on average to 2016.
For the longer term, we confirm growth of more than 3% per year to 2022. This is based on a low decline rate, without 4% coming from dynamic reservoir management and intense production optimization activities, and our diversified synergic development pipeline. Within four years, our new project will contribute more than 700,000 barrels per day of production. Of this, 65% is already sanctioned, and 90% will be sanctioned by year-end. 80% of these new projects will come from giant projects, and 40% will come from additional development phases of producing fields. Most of our new projects are in our development hubs, where we can leverage on two types of synergy, geological expertise, and scale advantages on operational and logistics. Our production will be increasingly resilient. It is already well-diversified among different geographical areas and will become even more balanced across our hubs.
More than 75% of our production will come from either onshore or shallow water, with a positive impact in term of risk and operating cost. And finally, in the next 10 years, almost 80% of our production will be operated. The next 22 months will be crucial for our growth. With the 15 major startups, which will deliver 450,000 barrels per day of new production by the end of the four-year plan or 60% of the new production we target. On this fundamental objective, we are in a very good shape. Progress is in line with schedule. Main projects for 2013 have either started up or undergoing commissioning and close to completion. On this project, we are deploying our best people to exercise strict control of operated activities. And now, an update on this project.
In Algeria, MLE started at the beginning of this year, is ramping up alongside the contribution of K7 early gas expected this month. The two projects are in the Berkine Basin, close to our existing operations. El Merk has recently started up. Equity contribution from the three Algerian projects in 2013 will be 30,000 barrels per day and will grow to 45,000 at the end of the plan period. Turning to Kashagan, we are making good progress. At the end of February, we started up the onshore facilities with sweet gas and diesel. The plant is ready to receive well production. Offshore, the A island will be ready for production by the end of this month, while on D island, we have achieved mechanical completion of Train 1 and are progressing well with commissioning. We expect a June start-up in line with contractual commitment.
Contribution to 2013 production will be around 20,000 barrels per day, ramping up to more than 60,000 barrels per day in 2015, following the start-up of the second raw gas injection facility in Q3 2014. Let's move to projects starting in 2014. In Russia, where over the last two years, project development has been faster than expected, [inaudible] are proceeding according to plan. These two projects will add 100,000 barrels per day of equity production to 2016, bringing the overall contribution from the Yamal hub to 165,000 barrels per day. In the Barents Sea, the Goliat project has reached 54% progress. Drilling is on schedule, and FPSO construction is progressing in the Hyundai area, with the sail away planned for the beginning of the next year. Start-up is expected in Q3 2014, with an average yearly equity production of about 20,000 barrels per day.
Equity peak production will reach 60,000 barrels per day by 2015. Another project that is making good progress is the West Hub in Block 1506 in Angola, where start-up is confirmed for 2014, with equity production reaching 25,000 barrels per day at the end of the plan period. For the East Hub, concept selection has been agreed with partners, the project will be sanctioned this year. Start-up will be in 2016 with an average equity production of more than 15,000 barrels per day. In Venezuela, the first phase of Perla gas project is on track, start-up is expected in the second half of 2014, with equity production of around 20,000 barrels per day by the end of the period. On Junin-5, we have just started up an anticipated early production around one year earlier than planned, leveraging on existing facilities.
This is very important as it allows us to de-risk the overall project by improving our knowledge of the reservoir, testing productivity, and assessing gathering system with a very limited financial exposure. Equity production will be around 30,000 barrels per day in 2016. To complete the overview of our projects in the last two years of our plan, we will have 11 major start-ups, which will add 150,000 barrels per day by the end of the plan. Five of these major projects are already sanctioned. All others will be sanctioned by the end of 2014. All are either in execution or in the front-end engineering phase, are progressing in line with plans. Moving to a longer-term outlook, Mozambique will be a pillar of our growth. We have completed eight wells and tested five, all successfully.
Potential proven resources account for 48 Tcf of gas in place, while 27 Tcf are exclusively within Area 4. This year, we plan to drill one final appraisal well on the Mamba complex and one or two new exploration wells. The appraisal phase will be completed in May, just 18 months after the first discovery. On development, Eni and Anadarko will jointly plan and build a common onshore LNG facility in Cabo Delgado. The initial development phase consists of four trains and 5 million tonnes per year each, and the site could potentially host 10 trains, equivalent to 50 million tonnes per year. We will now proceed rapidly with the technical and commercial activities. We foresee FID in 2014 and first cargo four years later.
As you are aware, a few hours ago, we finalized an important transaction related to these assets. To answer to your question after the presentation. Two more key pillars of our long-term growth are the Barents Sea and Indonesia. In the Barents Sea, the development of Sleipner and Wisting is progressing. The development concept has been selected, and startup is expected in 2018. In the Pacific basin, we are continuing our strategy of organic growth in a robust market, leveraging on synergy with existing facilities. During this year, we will take the FID for the Jangkrik development project in Indonesia. Production startup is expected in 2016, with an equity contribution of 5,000 barrels per day. Indonesia will contribute over 100,000 barrels per day of production by 2022 through the Jangkrik complex, Jau and Kutai Basin.
Turning to exploration, we expect to continue our track record of value creation. In Russia, we are progressing well thanks to good cooperation with Rosneft. We have set the operating companies, and we are preparing to drill in 2015. Our program in there over the next four years encompasses more than EUR 300 million of CapEx. The Gulf of Mexico and Asia Pacific will be key areas for our exploration, accounting for nearly 20% of our exploration investment in the four-year plan. In particular, this year we will start activities in Vietnam, drilling our first well just a few months after obtaining the licenses. Meanwhile, near field exploration will be mainly focused in our legacy areas of North Africa, Pakistan, and Congo.
We will drill more than 230 exploration wells in the next four years. We confirm our target of 1 billion barrels of discovered resources per year with a very efficient cost position of $2 per barrel. Rejuvenating our exploration portfolio is a constant priority. In 2012, we added more than 80,000 square kilometers of new acreage to our basket, mainly in the Barents Sea, in East Africa and Vietnam. As a part of the transaction which finalized a few hours ago on Mozambique, we are entering Rongchang block in Sichuan Basin in China, one of the most prolific shale gas basins in the world. We will be glad to answer your question on this after the presentation. Our growth will be funded by about EUR 47 billion of CapEx in the next four years, an increase of 5.5% over the previous plan.
The variation is driven by three factors. Evolution of the portfolio, with projects being completed in Kazakhstan, U.K., and Norway, and the start of major expenditure in Mozambique, Indonesia, and offshore Nigeria. Cost inflation for services and material, and exchange rate with around EUR 1.5 billion increase due to the appreciation of U.S. dollar versus euro. Development CapEx will be geographically diversified and concentrated on development with fast startup. More than 75% of the CapEx is related to activities and project with production in the four-year plan horizon. Exploration CapEx will follow an allocation similar to the past years, with 25% dedicated to frontier exploration, 45% to proven basins, and 30% to near-field activity. Our growth will be both valuable and resilient. Operating costs will remain among the lowest in the industries, notwithstanding the startup of new large projects, which are mainly under PSC contracts.
Finding and development costs will continue to improve, driven by confirmed low exploration costs and efficient development. In addition, a steady flow of promotion to proven reserves will be guaranteed by the time-efficient functioning of our projects. Our assets will deliver attractive cash generation and returns. Rebasing 2012 cash flow per barrel to our scenario of $90 per barrel, the increase to 2016 will be around 15%, thanks to the increased proportion of oil in our new production. Looking at return, the internal rate on new projects will be strong, around 20% at our scenario of $90, thanks to contained development costs and our focus on rapid delivery. Breakeven price on new production will remain at $45 per barrel, preserving profitability.
Starting from 30% in 2012, inactive capital employed will be around 20% at the end of the plan period, thanks to production startups and to our strategy to develop giant field by phase. In conclusion, we are entering into a very strong period for Eni. We are fully focused on our drivers, accelerating conversion of resources, delivering our project into production, successful and valuable exploration, and increasing returns through the continuous improvement of our performance. Overall, we are in a better position than ever before to deliver sustainable long-term growth. Thank you. We now hand over to Marco.
Thank you, Claudio. Good afternoon, ladies and gentlemen. The European gas business has changed quite a bit over the last few years, and the revolution is not yet over. Today, I would like to go through the main changes that have impacted the market, and more importantly, the decisive steps we're taking to reposition ourselves and return this business to profitability in the core areas. Starting with the market. As Paolo highlighted, we're seeing further deterioration in 2013, mainly in Italy. There's three reasons for this. First, demand is poor, suffering from industrial production decline, substitution of renewables and coal in the power sector, and slower demand coming from outside. Second, supply is not falling in line with demand due to the take-or-pay volumes that are being delivered into Italy and to their rigidity.
Third, and this is quite peculiar to the Italian market, there's no reverse flow capacity, so when the gas comes in, it cannot go out. There's no physical export routes out of Italy in the north. The result of this is that overall the Italian market is oversupplied, and this is reflected in the dramatic drop of the PSV price that went from a steady premium of around EUR 350 per thousand cubic meters for the northern hubs to price levels now that are below the hubs. This level, unfortunately, is also below our supply cost based on the long-term take-or-pay contracts that are oil indexed. In this challenging context, we're taking concrete steps and action to reduce supply costs and to enhance our commercial offering. Let's look at these areas in more detail, starting with supply.
We are proactively engaged with all our major suppliers in formal price discussions. We regard this as an opportunity to positively reposition this business. We have set ourselves two ambitious targets. The first is on price. We want to align prices with the hub level, less logistic costs. Our second target is to reduce minimum contractual volumes so that we can increase the flexibility in our portfolio, and we can cope with volatile demand. We are confident in our targets because of our contractual or legal rights to a competitive price and a profitable business. To predict the exact timing is more difficult, as implementing these contracts and the structural changes that we want to implement in the contracts will take time, and in some cases, it will require more than one negotiating round.
Some suppliers have their own interpretation of the contracts and of the markets, and that's why we're considering all options, including arbitration. If the negotiation turns into an arbitration, what we would normally expect to close in a matter of months may turn into a couple of years. Our approach here is always to favor a good deal over a quick deal. Also because delayed settlements have retroactive compensation, so the overall economic value of the deal is not itself impacted by the timing of closing. Given the uncertain timing, we will have quarterly volatility in both earnings and cash flow until the negotiations are settled. Based on the current discussions we're having, we believe that we can bring ready benefits to our overall supply position in 2013. A rebased supply portfolio is the first pillar of a profitable and sustainable Gas & Power division.
The second is an attractive commercial offer. Let's look at our market strategy in more detail. Here we have three main building blocks. Starting with industrial and wholesale customers, we have integrated our sales and trading platforms in order to develop new structured products that our clients are increasingly asking for. In today's hub-based environment, even the smaller companies and the industries are asking for quite sophisticated pricing when they buy gas from us. We have everything we need in this environment to position ourselves in the more attractive niches and make profit from this going forward. Second Asset-backed trading. We have a top-class organization based here in London. Their main activity is to do very low-risk arbitrage, whether it's geographical arbitrage between different locations or time arbitrage between different time horizons, to extract the embedded value we have in our unique asset portfolio.
We see steady and growing profits in this business. Our third commercial activity is LNG. We have recently combined our short and long-term portfolios to create a single integrated commercial LNG team for Eni. We will continue to generate profits mainly through cargo diversions to Asia and South America, even if we expect the price premium to shrink, as Paolo mentioned. In LNG, we work very closely with Claudio and E&P, and we have just returned from a marketing trip in the Far East, where we are beginning to sell the volumes for Mozambique. Adding all these three blocks together, in our merchant activities, we expect that we can make around EUR 600 million of EBITDA by 2016. This is once we've brought supply costs in line with the market. Adding back the retail and semi-regulated, we get to the EUR 1.5 billion EBITDA target that Paolo talked about.
We have some upside. Based on the size and solidity of our Gas & Power portfolio, we believe we're well exposed to potential recovery in Europe. There are several potential triggers for the market to tighten. The four we think we should watch more closely are: first, decisions on nuclear phase-outs in Taiwan, in Japan, and indeed in Europe. Second is continuing growth in LNG imports, not only in China, but also in India, in South America, and indeed, in the Middle East. The third is new European legislation on CO2 or on coal. Finally, a more rapid decline in European production. In North Africa, we're seeing the gas balancing tightening quite quickly as they consume more and more gas.
We don't need all of these to happen at the same time and any combination to drive price higher, as there is not that much spare capacity in Europe right now. After all, last week was a seven-year high in Northern European hubs for gas prices based on concerns of limited flexibility. In conclusion, even if the two years ahead will be challenging and volatile, we are making steady progress to restore profitability in our core contracts. We're integrating our operating platforms and enhancing our commercial capabilities in both pipeline gas and in LNG. Overall, we're confident we have everything we need to generate significant, sustainable, long-term profits in Gas & Power. Thank you very much for your attention. I'll now hand over to Massimo for the financial outlook.
Thank you, Marco. Good afternoon, ladies and gentlemen. Eni strategic growth prospects are supported by a strengthened financial structure. With the net debt at the year-end 2012, almost half of its level at the end of 2011, and leverage at 0.25. This stronger financial position is current with our new business profile, more exposed to the E&P business. Going forward, we expect to maintain leverage within the range of 10%-30%, using this flexibility to absorb temporary fluctuation in oil prices, in market environments, and in our business results. As well as lower net debt, we are also holding a stronger liquidity position. Our aim in the current market scenario is to retain cash and cash equivalents to cover around two years of refinancing needs, ensuring sufficient independence from the credit and banking systems.
Meanwhile, over the next four years, we will invest EUR 57 billion to fuel the growth highlighted today. This is broadly stable compared with the investment plan we presented last year. Excluding the effect of a stronger dollar we now anticipate, the increase amounts to around EUR 1.6 billion or less than 3%. The increase is largely related to the improved growth opportunities in E&P, including Mozambique, partly offset by the completion of Kashagan. Indeed, our plan is focused on E&P, which accounts for 83% of the total investment and 90% of discretionary investment, where discretionary means excluding essential maintenance and HSE in other segments. Other increases relate to Versalis, with the addition of EUR 400 million over four years to support the turnaround in Saipem, which plans to complete the fabrication yard in Brazil and upgrade some vessels and onshore rigs.
With regard to Gas & Power and R&M, we are increasingly selective in capital allocation, and our combined plan is 15% lower than the plan of last year. Taking a closer look at our midstream businesses, CapEx will be largely concentrated on efficiency programs and the refocusing of our portfolio on more attractive niches. In Gas & Power, around 60% of the investment plan is related to power generation. Other investment include upgrades in gas transport and distribution, businesses with resilient returns. In refining, a key project will be the conversion of Venice into a biorefinery to recover profitability. The EST plan in Sannazzaro, exploiting our proprietary technology for the full conversion of the barrel, will be on stream in the second half of 2013, improving the complexity of our overall refining system.
Remaining CapEx will include the maintenance and upgrade of our refineries, logistic enhancement, and non-oil development on our service stations. Finally, chemical CapEx will be focused on new initiatives to reduce exposure to basic chemicals and refocus on better segments and geographies. The increase of EUR 500 million is related to the conversion of Priolo and Porto Torres to the attractive segments of elastomers, resins, and green chemicals, reducing the capacity of ethylene and polyethylene and increasing the 2016 EBIT by EUR 150 million at 2012 scenario. Our CapEx plan will be more than fully funded by a strong cash generation. We project stable cash flow in the region of EUR 20 billion per year over the plan period. Our operation will deliver growing cash flow during the next four years, driven by increasing E&P production and the gradual recovery in our mid and downstream businesses, mainly Gas & Power.
On top of that, disposals will deliver more than EUR 10 billion of additional cash flow. These include the rest of Snam and Galp, the divestment we have announced today about Mozambique, and other E&P disposals, benefiting from this substantial exploration success recently achieved. We expect this program to be front-end loaded mainly over the first two years. The plan does not include the potential upside from higher oil prices, and on this respect, our sensitivity is around EUR 120 million on cash flow for every additional USD on Brent price. Now I will hand you back to Paolo for his closing remarks.
Thank you, Massimo. The strategy and targets we have set out today will generate significant cash flows, which is the basis of our new shareholder distribution policy. As you know, this year, we have taken a fresh look at the way we return cash to shareholders, because with the sale of Snam, we are now a different company, more E&P and less regulated, more growth and more volatility, less debt and more liquidity. The new Eni will return cash to shareholders through, one, a progressive dividend policy, plus, second, a new buyback program. Let's look at both in detail. First, the dividend. Well, this will be progressive, growing over time at a rate which broadly reflects the group's underlying earnings and cash flow growth while taking into account investment requirements and the overall financial structure.
This dividend policy is based on our plan scenario, which includes $90 a barrel and a gradual European demand recovery. According to this policy and on the basis of our projections, the dividend which I would propose to the Eni board for 2013 would be EUR 1.10 a share, an increase of around 2% on 2012. Second, the buyback. This will be activated at management discretion and when a number of conditions are met. These include, but are not limited to, satisfactory leverage well within our target range, and full coverage for CapEx and dividends throughout the plan period. Just to give you an idea, but it's just an idea of our mental framework rather than a forecast. No forecast, just an idea.
For 2013, should we see oil prices remaining at current levels, and should we be making good progress on our business and cash flow targets, we would consider the activation of the buyback. Now, I will bring the former part of this presentation to a close. Before I open up the floor to Q&A, I wanted to wrap up by highlighting the extraordinary growth period that we are about to enter. The basis of our growth will be the start-ups we will deliver this year and in 2014. 2013 and 2014 are two crucial years for start-ups. Our long-term prospects are ensured by the transformational discoveries which we have made and the high-impact exploration package of our portfolio.
At the same time, we are making progress on the restructuring of our mid and downstream businesses, rebasing the gas business for sustainable profitability in a hub-based world, cutting cost and capacity in R&M, refocusing the chemicals portfolio on profitable segments. In addition, we are further upside from disposal, which will push to maximize value for our shareholders. Thank you for your attention, we will now be delighted to answer your questions.
Ladies and gentlemen, we're opening the floor for Q&A. We will take questions from the room first. Could you put up your hand, of course, and when you ask a question, could you stand up and state your name and company name, please? Can you go over there, please?
Hey, Alessandro Micheli from Exane BNP Paribas. Couple of questions for me. Starting with the buyback, you gave us your thinking about some parameters here. Maybe you can tell us where do you think you can stop the buyback, in which kind of parameters of oil price, what kind of conditions? Second thing on the R&M target, you gave us the starting point of 2012. Maybe you can tell us what's the sensitivity around that target, given that 2012 was a good year for refining in general.
Okay, you answer this. Let me just comment the buyback. First of all, as you might have understood by my answer, we want to keep maximum discretion and flexibility on the buyback. We want to be able to take decisions completely freely, and we are reluctant to give any kind of forecast. Having said that, one thing is I would take it for granted. If the oil price will be this year at our scenario, EUR 90, which is possibly unlikely, but is still a possibility, we will not activate buyback. The whole idea we have is that the buyback is an instrument to give back cash to shareholders when the scenario is more generous towards us than we would expect in general. Now, let me answer. Maybe I ask Massimo to answer the second question.
Okay. If I understood you, I think some more detail about our plan to reach more than a breakeven in 2016. Just to recall that we already got some significant improvement in 2012, reducing our functioning cost, mainly in supplying energy, reducing energy consumption, amounting to more than EUR 100 million. If I say more precisely, EUR 120. The expected reduction in our refining capacity by around 10%, with the close down or reduction in capacity of our Venice refinery will help to reach this result. The EST investment that will be ready for production by mid of this year in the Sannazzaro refinery will help to complete substantially the plan. Our overall synergy are expected to reach around EUR 500 million. That means that 2016, using the same scenario we are experiencing in 2012, an EBIT result that would be around EUR 200 million.
Microphone down here.
Hi, Iain Reid from Jefferies. Paolo, can I ask you another question about the buyback? It's on the disposals, particularly of Galp and the remainder of Snam. If you manage to sell those this year, is that some sort of trigger for you as well, even though oil prices may not be perhaps high enough on an organic basis to start the buyback? I've got a follow on from Claudio as well. Just a minor quibble on your presentation. Going back to what you showed us last, whenever it was September, October. You showed F&D costs at that time falling quite considerably to about $15 per barrel in 2012 to 2015. You've now shown them pretty much flat. Looks like about $20 a barrel going forward. Is there any reason for this quite a sharp increase in F&D?
Okay. While Claudio thinks to answer your second question, let me answer the first one, which is complex. Listen. On the buyback. Let me first give you a number. Within our numbers for the plan, we forecast EUR 10 billion of divestment, EUR 10 billion. These EUR 10 billion are composed by EUR 5 billion, which are either the shares of Snam and the shares of Galp, which we plan to sell within the plan period, and the two convertible bonds, exchangeable bonds that we have launched, which are supposed to be paid back by 2016. The sum of all this, let's say everything around Galp and Snam is worth EUR 5 billion, more or less. We have another EUR 3 billion of Mamba of Mozambique, okay? Which are the $4.2 billion translated in euros.
In total, we have already identified, not yet achieved, but identified EUR 8 billion out of EUR 10 billion. We have EUR 2 billion more because we always made some portfolio management, and here we are taking a four-year period, so a pretty long figure. All these numbers are already in our plan. Since a must we have is to keep a very strong balance sheet, we want to have a very strong balance sheet for the future. These activities, we will not consider these divestments exceptionals. We include them in our numbers. To answer your question, no, this divestment will not be the reason of a buyback. The reason of buyback would be more an oil price exceeding our scenario. The second question, Claudio.
The second question on F&D. What we said on the average between 2015 and 2016 that I presented in October, didn't consider the update with the new big projects. There is a new project, and there is now all the effect of the new FID sanction. There is a slight increase of $1.3 per barrel. That is the increase due to the new project.
Thank you. It's Irene Himona, Societe Generale. I had three questions, please. First, you show a chart, I think it's slide 41, with a fairly stable cash flow from operations of EUR 20 billion. Earlier you said that the capital employed in service will move from about, or not in service rather, from 30% to 20%. Therefore, I would have expected an increase in cash flow from operations from that. I wonder why that is not the case. Okay. My other two questions relate to Mozambique. I think it was mentioned that you're already pre-selling volumes into Asia. Can you indicate if that is on oil price indexation? And secondly, your remaining 50% stake following today's disposal, is that a level you're happy with? Given the size of that project, would you potentially look to reduce exposure? Thank you.
Irene, I'll answer your first question. Is it possible maybe to project again slide 41? Because, okay, you are perfectly right, Irene. It's a matter of color that has been used for this slide.
We'll get there
Carefully look at the slide, you could see that the operational cash flow will increase all along the four years. It will start very close to the CapEx line by 2013, ending up at a very high level in 2016. The difference to have an overall cash flow stable is due to the disposal. That, as I said, will be front-loaded, mainly concentrated in 2013 and 2014. The sum of the two components will end up with a stable cash flow of EUR 20 billion per year.
On Mozambique. First of all, to answer your question, no, we have not set any price with anybody, no pre-sold quantity, no nothing of that sort. It's really very premature. What has been central in our strategy around Mozambique was, in order to give value at the huge discovery, to have potential customers among the shareholders. We have done it with KOGAS is certainly a big customer of LNG in the world. It's a kind of traditional partner of ours. You might know that it's together with us in Cyprus, is together with us in Iraq. We have a, let's say, an easy relationship with them. Now with CNPC, which of course is potentially a big customer for this gas. The whole idea is that to have customers and maybe in the near future, having even contracts with them.
As soon as we move ahead, it gives robustness to our project, because when you have already pre-sold gas, everything flows much easier. As far as our 50% stake. We were sitting comfortably on 70%, we are sitting even more comfortably on the 50%. Having said that, again, if we could, through a sale of part of those shares to give more solidity to our project, we would certainly consider.
Hi, hello, it's Martijn Rats. I'm with Morgan Stanley. I wanted to ask you three questions. The first relates to the dividend, which has increased 2% in the presentation that you gave. Which is a little less than the trend growth rate that we've seen over the last few years. I was wondering, with the different mix between share buybacks and dividends that we're now getting, whether the 2% also signals a lower trend rate going forward in future years, or whether this is sort of a one-off from that perspective. The other question I wanted to ask is about your base case scenario of $90 a barrel. I just wanted to confirm that if oil prices were to fall to that level tomorrow, would you expect the entire CapEx program to be pretty much unaffected? If that actually were to happen, would there still be a change?
I had a question for Mr. Alverà. You mentioned that you would expect the Asian premium from LNG to slowly erode over time, and I was wondering if you could put some numbers around that. Over what time frame, roughly by what magnitude? How are you thinking about that?
The dividend. Don't look at this dividend as a trend from last year. This is a new phase, a new Eni, a new policy, new balance sheet, new debt level, we wanted to start with a dividend which is fairly generous in the industry. I don't know if we are the top dividend yield company in the sector, but if we are not the top, we are certainly very close to the top. We started with a EUR 1.10 dividend, which is something which we consider reasonable in terms of share price, and that's it. In the future, every year, we'll take this decision according to, as I said, the total growth of the company in terms of profits, cash flow, et cetera.
As far as the $90 per barrel and our CapEx plan, I think that Claudio pointed out that we have a breakeven at $45. If the oil price tomorrow will be at 90, our CapEx plan will not change. In terms of what we do expect about gas prices in the world and particularly in Asia, I don't think that everyone has a clear view, but maybe Marco wants to add something.
When I was speaking, I was talking specifically about our plan in 2016 compared to 2012 or 2013. We've seen last year incredibly high premiums that we don't think are structurally plannable in prudent forecasting over four years. We are seeing a lot of demand, they're not going to probably disappear, but we're just planning prudently and not assuming that that gap between European prices and LNG prices stay stable.
Yes. Thank you. Hello? Thank you. Roberto Ranieri from Banca Intesa. A few questions, if I may. First one is about the unit exploration cost, and you told us that it is in the region of EUR 2 per barrel. My question is if Mozambique is included. If not, what will be the change of this exploration cost per barrel in the future with including Mozambique? My second question is on the gas business. Reverse flow, which is important for the Italian gas hub. My question is when we can expect a reverse flow. I suppose when the Snam investments will be completed. My question is presumably the timing of a substantial reverse flow capacity in Italy.
My other question is on the Gas & Power, which is the current portion of the spot market in Italy, and what Eni is now purchasing in this spot market, and if you see this portion to increase in the future to reduce the supply cost? In that case, what is your target for take-or-pay flexibility in your renegotiation? We heard about 30% flexibility from other operators, and my question is if you can target this level. My final question is on [DMP] as well. Just if you can remind me, maybe I missed the value. New projects are 700,000 per day. My question is, what is the depletion rate?
Of the production, which partially offset this growth. Thank you very much.
Claudio, you start with the two.
the unit exploration cost of $2 per barrel is a projection for the future considering to discover 1 billion barrels of resources every year. Considering Mozambique, we talk about the past, and in 2012, we had $0.60 per barrel, and the average over the last three years was $1.20 per barrel. The $2 is a projection, considering 1 billion. Yes, the depletion rate is 4%, and that is on top. That is what is the net contribution of our project in the next four years.
On the reverse flow. First comment I would make is we don't need a lot of capacity, and we're working with, it's actually Fluxys, not Snam, on some work that has to be done in Germany to see if the conditions are there to take an investment later this year. It's not very difficult to do because the pipelines are already in place, and if everything goes as planned, there could be some reverse flow available in 2015 or 2016. It was encouraging to read this morning that Snam also believes it's a strategic asset, and there, it's more of a system play than any specific play. For Italy and for the market in general, to be able to export some volumes is a positive thing. Talking about the hub, the Italian hub has become increasingly liquid very rapidly, I would say.
It's not yet liquid as the northern hubs are, but it is becoming very liquid. In terms of our buying strategy, apart from maybe some small optimization volumes, we are so long structurally gas, that we don't plan to buy significant volumes in the PSV, as that would not really help our take-or-pay situation. In terms of specific flexibility, we are working on our overall portfolio approach by reducing some minimum contractual volumes. This will give us flexibility at the portfolio level, but we're not setting specific targets for contracts. There may be some suppliers with whom it's easier to reduce volumes and some suppliers who may favor reducing prices. We take this at a portfolio level, and we're not giving specific volume reduction targets.
Thank you. It's Jon Rigby from UBS. Three detailed questions, really. The first is, I think last year, in your projections for gas, I think you talked about a 50 BCM increase over the planning period in demand across Europe as part of the scenario, and I just wondered what you were thinking about this time around as you put that into your plan. I suspect it may be in your upside, but if you can maybe talk about that'd be great. The second, I guess is for Massimo, is that when you look at your cash flow targets, one thing that occurs to me when I look at your 2012 performance is just how much cash flow is soaked up in the working capital movements of the business. I just wondered, A, what you were projecting over the next four or five years in your projections.
Second is whether there's work to do in terms of upside to get some of that cash back, to be perfectly frank. The third question is for Claudio. On a non-risk basis, I guess is the best way of looking at it, which of the wells or the activities that you've got coming up through the 2013 exploration program that we should keep a very close eye on given your track record over the last few years? Thanks.
Let's start from gas demand.
Thank you for the question. In the numbers you saw, which lead to the 1.5 target, we're staying quite prudent on growth. We're assuming 0.2, or let's say zero growth too, in Italy, based on 2012 figures that you know were very low compared to the previous years. This would bring Italy to basically level of 2003, 2004, and that's about 75 BCM. In terms of Europe, again, we're assuming only 0.5% annual growth, and this would bring to volumes in 2016, which is our end year, basically in line with 2010, 2011. We're taking a prudent growth. That's why we have this upside situation where if the market does pick up, we're geared to participate in that.
Go on cash flow.
On cash flow, yes, the working capital absorbed a significant amount of cash in 2012, mainly due to Saipem and to Gas & Power. The overall amount is higher than EUR 1 billion in 2012. What about our expectation? We expect that this amount will be slightly recover in the first two, three years and will be, in our projection, fully recovered as far as Saipem is concerned, and quite fully recovered, even if not all, in Gas & Power due to the slightly recovering gas demand.
Exploration.
Exploration to 2013. We're going to continue and finish our exploration in Mozambique. I think that is another interesting part of our exploration. Finish the appraisal campaign, and we are going to start a new exploration campaign with the first well that will be drilled in July. Now is in different kind of environment, different target, and mainly oil. That is quite important. Going to West Africa, I think that there are three countries where we are drilling. One country where we are drilling pre-salt horizon that has been very successful, and we continue in Congo. In pre-salt Congo, Brazzaville, and we have to drill other wells there for oil, and Ghana. Also we have other three prospects in the Block 1506. Now we finished the appraisal campaign for the west and the east hub.
We're going to sanction the east hub, and we can start and restart again the pure exploration in Angola. We have two wells in the Barents Sea, and I hope that they will be very important wells for us. We have the first well in Vietnam, as we said before, and we restart exploration in the Gulf of Mexico. The Gulf of Mexico, as I said before, in the four-year plan, it will be very interesting and important for Eni. We have 20% of our budget in the Gulf of Mexico. Overall, we are going to drill between 60 and 70 wells in exploration. We have a budget that is about $2.5 billion.
Yeah, hi. It's Michael Ridley from Mizuho International. Two questions, really. You spoke many times about wanting to have a strong or very strong balance sheet, and I know you've got a debt for equity ratio target. I'm just wondering if you had any other parameters to guide us there. Do you have a net debt to EBITDA target or a rating target? Say, if you were not impacted by the Italian sovereign rating, what would be your goal as a rating? Second question, hybrid issuance. BG's issued hybrids, and Enel is looking at $5 billion over the next three years. Just wondering if you have views on that, or you might rule out issuing a hybrid. Thank you. Okay, the hybrid debt security is the sort of perpetual quasi-equity instrument that's quite common now in utilities in some oil and gas companies. BG, for example.
As far as the first question, no, we don't have any specific target in terms of net debt. Our target is the one we declare, so the range between 10% and 30% in terms of leverage. As leverage, 30% means the maximum level. Just to highlight how strong we'll be in terms of balance sheet, I mentioned our aim to be self-sufficient in terms of refinancing with liquidity available in the short term to be independent from the banking system. On top of that, we are retaining significant amount of committed credit lines, this would be, I would say, our aim to retain the stronger balance sheet and defend this possible, our rating from the outside environment.
Just to add a number to what Massimo has told you. As we speak, we have roughly EUR 18 billion of bonds outstanding. Am I correct? We have in cash roughly
EUR nine billion.
EUR nine billion. Okay. We feel comfortable with that. We feel comfortable with that kind of numbers. Now, on the hybrid, I don't think we have in mind to issue hybrids right now, no.
Rahim Karim from Barclays. Three questions, if I may. The first was just with respect to the diversification that you talked about, Paolo. In the upstream business, you gave us a useful chart on slide three around capital employed in the various parts of your business. There was something that showed quite a large growth in Sub-Saharan Africa, almost close to 40% of your capital employed in 2016 being in that part of the world. I just thought I'd be interested to get your views on whether you thought that was diversified enough, and whether we should expect some sort of portfolio action in that part of the world. The second question was just perhaps to get a sense of the kinds of returns that you might be expecting from the new operations in the synergies within the trading business in it.
Bringing together the Gas & Power and the R&M, give us any sense of what profitability uplift that could give, and perhaps the capital deployment Back to Jon's question earlier. The third question was just to come back to the $90 kind of scenario that you the oil price be there? Or is it an oil price above $90 over the next four years at which the buyback should start to commence? Thank you.
Thank you for your questions. I answer first the third one. I cannot say never, but in principle, if we stay in $90, we'll make no buyback. That's just to give you what is my view.
On diversification. Of course, Eni today is very much dependent on the E&P, and is dependent on the geographical distribution of E&P. We are different from many other oil companies, the traditional ones, which are somewhat national oil companies. If you take the large American international oil companies, most of them produce more than 50% of their production in the U.S. and in Canada. Why we, unfortunately, we do not have a home country which is so generous in hydrocarbon. We have been expanding in areas of the world, such as North Africa, where we have a major role, but of course, Sub-Saharan Africa and other countries. We would like to use our exploration successes in order to have a wider distribution of our resources. We still consider Africa our homeland. We are by far the biggest producer of hydrocarbons in Africa.
We have the biggest presence in Africa, we consider that we know particularly well Africa. On top of that, when you look at the investments we plan to do in Sub-Saharan Africa, Mozambique will play a major role, but also Angola, Ghana, a whole series of old and new countries for us. On Gas & Power and R&M and the synergy with trading, the only one thing I would like to point out before I let Marco explain to you the synergy, is that we are organized in such a way that trading, for us, is not a profit center, or rather, it is a profit center, but then it distributes the profits to the Gas & Power and the R&M division. You will never see a number for trading, because the number for trading will go into the two divisions that generate the profit.
Of course, Marco will give you an idea of how the synergies would be generating additional profits for the two divisions.
I will talk separately for the gas and for the oil business. On the gas side, the integration of the two activities is really allowing us to serve the customer. The market has evolved quite rapidly. The customers want now new products that are much more similar to a product that's traded through a trading organization than just selling normal gas through a sales organization. The upside there, you would find on the commercial margin that Gas & Power makes on the industrial and wholesale by selling this optionality. Of course, this activity is done very closely with our portfolio management and our risk management because they are the owners of the assets, so they need to come up with the flexibility that we have and then transfer it to the market.
On the oil side, the first step that we're taking right now, that we've taken a month and a half ago, is to integrate Angelo's supply business with the trading business. Until now, we had supply people taking purchase decisions for the refineries, what crude to buy, when to buy it, and they were separate from trading. Putting them together, certainly they would have a single view, they would be more effective in the market. We expect some upside that is included in the projections that you've seen for refining. In terms of working capital, overall, we expect working capital to improve as the take-or-pay positions get reabsorbed over the plan period. Because we don't do a lot of, let's say, commercial third-party trading, we don't need a lot of additional working capital.
Anyhow, whatever capital we deploy also on the trading side is subject to our strict internal hurdles and WACC and normal metrics that you would have on CapEx decisions.
Ladies and gentlemen, I would like to remind you that you can register for your question by pressing star followed by one.
Hi there. It's Jason Kenney from Santander. Thanks for your presentation today. Enel this week has mooted that it might divest its 19.6% stake in SeverEnergia in Russia, I just wondered if this could impact your position there, or indeed, if you could even see consolidation in that asset, given that your cash flow is quite positive at the minute. Secondly, could you give me a guidance on the tax charge going forward with the new Eni board structure? Thirdly, given recent events, has the board reconsidered the position of Saipem within the Eni group? Could you maybe just reiterate the pros and cons for keeping your interest in Saipem?
On SeverEnergia, yes, we would like to be interested in Enel's stake. Unfortunately, the new law in Russia forbids any foreigner to own more than 25% of an asset. We are already at the level of 30%, I'm afraid we cannot be a bidder for this very valuable asset that we have.
Okay, on tax charges, I'd like to give you an answer speaking about tax rate. We recorded a tax rate in 2012 that was around 61%. What about our expectation? We expect a slightly increase in tax rate in 2013, around 64%-65%, due to the fact that the majority, if not the whole income, will come from the E&P that you know is exposed to a higher tax rate all around the world. The tax rate is expected to fall down all along the four-year plan because of two reasons. First of all, because we expect a decline in tax rate even in E&P because of the increase in production in countries which have a lower tax rate. Because we expect an increase in the pre-tax income produced by the other businesses, such as Gas & Power and R&M, as we described before.
On Saipem. For the time being, we do not see a reason to give ourselves a timing to look again at our Saipem stake. Just let me point out that Saipem for Eni has been a phenomenal investment. From the time in which Saipem has been listed, the share price multiplied by 18, if I'm not wrong. 18 times in the last, say, less than 20 years. It has been an extremely good investment. Even at the share prices of today, remains a very good investment. As I think I said, as before, we are always ready to look at our portfolio with the view of creating shareholder value. This might happen even in the case of Saipem. For the time being, we see no rush to look into it.
Good afternoon. [Tipan] from Nomura International. Could we talk a little bit about your unconventional strategy? Firstly, just on today's announcement, if you could talk a little bit about the opportunity in terms of resource and whether you specifically negotiated for that block and what you saw in the block in the Sichuan Basin. Secondly, just in terms of do you see further opportunities in North America to build a position like some of your peers have done, or do you think it's too late? Thirdly, perhaps, with the changes recently in Venezuela, is there a greater opportunity for Eni to put more capital work in that country? Thank you.
Could you repeat the third one?
Sorry. In terms of Venezuela-
Venezuela.
-is there an opportunity?
Venezuela, yeah. Before I give Claudio the opportunity to speak more specifically about unconventional, and particularly unconventional in China, let me try to give you a couple of thoughts. First of all, as far as unconventional gas is concerned, the real issue is how to make any money out of unconventional gas. Our impression is that so far, not many investments in the area have been really very profitable for anybody. Let's say there is prudence because one thing is everyone likes the idea of producing unconventional gas, but we like more the idea of making money out of unconventional gas, which is a different story. Second, we invested in North America with Quicksilver. I think we've been probably the first European company entering into this new area. It was 2008 or 2009. 2007, even. It was a long time ago.
We made a small investment, if I remember well, EUR 300 million. The whole idea was to learn rather than to become a player in the North American market for gas. We certainly do not regret not to have made big investments in unconventional gas in the U.S. Maybe Claudio will expand a little bit specifically on China and also on unconventional oil. Let me say a word about Venezuela. Venezuela, so far for us has been a success story. We started production yesterday on Junin-5, well in advance as compared to our plans. We made a big discovery in Perla. In terms of hydrocarbons, our presence in Venezuela is extremely strong because not only we have oil, but we have gas, and gas might be used to upgrade the heavy oil.
In total, we believe that our position is strong, and we are looking to continue our plan of expansion in Venezuela.
For China, I think that the Rongchang block that in the Sichuan Basin is probably the best area in China. We can say that is the best area because already we have different wells drilled with very good success. We think that from a technical point of view, is a really a very good block, 2,000 sq km of block. We think to have about six and 10 Tcf
In terms of reserves, our preliminary feasibility study of development, I think being a possible production between 150 and 2,000 barrels per day or equivalent, and in a market that is a very good market. China needs gas. The area is very good. It's also close to a graded network of pipeline. It's southwest of 1,000 km south of Beijing, is a very good area. We have a special study on the environment because there are a lot of people. We have water, but really the HSE impact study has been already started. We have one year of study with the CNPC. I think that is a very good block that we can develop very quickly after the signature of the PSC. We start this new venture, and we started this block in the last three years. It's not a new thing.
It's here. For that reason, we had the transaction with CNPC, not just to give value to our amazing new block, but also to be able to stay pinned in this very good area. We are one of the few company that succeeded.
Thank you. It's Colin Smith from VTB Capital. I've got two questions. I think at the beginning of last year, you had closed gas contract renegotiations with everyone apart from Statoil, everyone. Can I just confirm that in order to reopen these, you're playing your joker clauses for all of the contracts that you had completed last year? Can I further ask whether you expect to get much of a positive response, particularly as the spot price in Europe is trading closer to the oil link price than it has for quite some time? As you mentioned yourselves, there's evidence of tightness within the market. My second question is on dividends. I think you mentioned that the dividend policy would be driven by growth in cash flow and profit, those two things look like they could be moving in quite divergent ways.
I just wondered if you could provide a little bit more clarity around, for example, whether you have a payout ratio in mind in relation to profit and in relation to cash, what sort of balance you'd be looking to achieve before you'd be moving the dividend, in that respect. Thank you.
Great.
On the first one. Actually we are now having open renegotiations with Statoil, with GasTerra, with Gazprom, with Sonatrach, and in Libya. Of these, only one may end up in using a jolly. The others happen to coincide, they're the natural evolution, either under previous agreements or the original contract. They're kind of all happening now. In terms of benefits, we're not concerned if that spread shrinks. In fact, if that spread shrinks, our current position improves. That's fine. We're working on two fronts on the pricing side. The first front is to make sure that gap doesn't exist anymore, because there's no reason why structurally we should pay more than what we can sell at. The second effort is to try to improve the indexation so that it's not 100% oil, we introduce over time some hub indexation to avoid any commodity mismatch.
These are the two efforts, they're ongoing, let's say, regardless of what that spread is at any point in time. We're trying to rebase the position so that it's sustainable going forward. A lot of these contracts were structured taking the Italian market into account. The changes that are happening in the Italian market are very relevant for our supply discussions.
About the dividend and how the two parameter you mentioned, price and CapEx, could play in order to drive our decision in future. I would say that as far as CapEx are concerned, we do not expect any significant change in the future in respect of what we discussed today. Why? Because, as Claudio already mentioned, 65% of the total CapEx of Eni, that amount 90% of the overall maneuver, already reach an FID. Means that the bid already open about the cost. Also, the cost is quite sure. The remaining part will be achieved up to 70% by the end of this year, 90% by the end of this year. As for the remaining part, we already embedded some inflation in the remaining cost.
Due to the fact that we have this flow of project that already full and a good, I would say, estimate about the cost, the result is that we expect that the dividend will be driven by the price and our capability to put in place exactly the program in exploration and production, and in Gas & Power, mainly, we have just disclosed.
Hi, Nitin Sharma from JP Morgan. Three questions, if I may. First one on dividend. What, if any, was the impact of current high yield on your decision to go for just 2% increase this year? Two on buyback. Starting with dividend again. What, if any, was the impact of the current high yield on your decision to go for a 2% increase in dividend? Second one on buyback. I think the original message around the announcement of buyback last year was to return excess cash from cash flow from the stake sales. Has that message not been diluted today by linking the buyback with oil price? Finally, on tax charge in Mozambique, could you guide us what sort of CGT would you incur on this deal that you've announced today in Mozambique? Thank you.
Okay. Now, on dividend, to your first question, the answer is no. The yield is not linked to the dividend we have paid. On the buyback, I think we never said, or at least I never said, that the buyback was linked to sales of stakes of Snam or whatever. I don't remember to have ever said that, certainly never thought that. The whole idea, if I may, because I've seen that this share buyback and dividend has raised a lot of interest of you, I would like to spend maybe one minute telling you what is my view. We live in a world, now more than before, which will be volatile. Oil price will go up, will go down. For example, if you want my view, I'm surprised to see the oil price so high, as far as I'm concerned.
I certainly am wrong, just give you my feeling. We want to guarantee to our investors, at least for the 4-year plan, a dividend which is stable and progressive, which makes some progression. Every time that we have the opportunity, because oil price is high, to buy back shares, we do it with the idea that the growth of the dividend can be assured with the same amount of cash, because we have less shares around. At the end of the day, what we are doing is what, in particular, U.S. companies have been doing for many, many years with huge success. I'm talking about our biggest competitors on the other side of the Atlantic. This is the general idea. On tax charges on Mozambique.
On tax charges on Mozambique, I would say that we expect a maximum tax charge of around 10% of the price of the transaction we announced today.
That gentleman over there.
Thank you. Peter Hutton from RBC. Just following on from that last point on my first question. Congratulations on the deal today, I see that the Mozambique Energy Minister has already suggested that you might like to share some of the value that you're attaining from that. Is that something which you think the deal today is going to impact the negotiations, given that the commercial terms on gas exports are still ongoing? That's the first question. The second is more specifically related to the gas business, one of the elements of your plan, I think, was mentioned to increase the number of customers from 11 million to 14 million, which I think is quite an aggressive expectation given that the environment is so difficult and you're in the middle of negotiation with third parties who are also supplying these in that market.
To what extent is the recovery based on that expectation of significant increase in the number of customers? Thanks.
Maybe Marco, you start, and then
Retail.
Retail. Please, we have Angelo Zaccari.
In terms of customers, we have experienced over the past a great increase. Talking of Italy, we have had significant competition, but growing a lot. The plan shows an increase of 3 million over the period. What I can say today, that within Europe and with the European approach that we are launching, every day 6,000 new customers are joining Eni. This is a great result. Of course, we want to build on this with this new European approach, both for the retail and the mid-market. We are currently present in Italy, which represents 90% of our activity. France and Belgium are doing pretty well. We are increasing our customer base. As I said, over the period, we will be growing by 3 million customers.
In terms of numbers, over the period, the commercial retail business is actually going to lose relative weight because of the regulatory environment in Italy that will change over the plan period.
I would just like to add that we are gaining 6,000 net customers a day, correct?
Working day.
Working day. Multiplied by 200 days, if we continue like that, this would be 1 million a year, more or less, which gives you the target of 4 million for the plan period. On Mozambique.
On Mozambique, first of all, the Minister didn't ask us anything. Didn't ask us to share anything at the moment. The transaction has been well prepared and discussed and shared with the President, with the Minister, with the government. It's not something that started overnight. We already discussed with them this kind of transaction. Also the buyer
At the end of the day, it is the government that has to decide who can buy the resources that we don't own, because that is a resource of Mozambique. On the second point, there is no commercial discussion with Mozambique because we already have an agreement on the basis of what we signed with Anadarko about the construction of the LNG plant. The only commercial discussion that we are going to have, also with the government, but with the state company, is about the gas that we are to sell. Having CNPC with us, that is a big plus also for Mozambique, because it's one of the biggest buyers. Having CNPC in the joint venture in Mozambique, also in the upstream and in midstream, it will be better for everybody.
Great. We only have time for a couple more questions. Perhaps I could also ask the people who are following us on the call to say whether they want to ask any questions. We will continue with the floor. Maybe one more.
Thank you. Christine [inaudible] from S&P Capital IQ. I have three questions. The first one, if we assume that you are very successful in meeting all your objectives, and in three, four years, well, in two years, we see that your share price starts going up substantially, which will mean your dividend yield will contract. Would you be happy with that? Or, as before, would you aim to be on the top tier of payout ratio? Will you want to keep a 5%-6% dividend yield? Or will you say, well, unlike before, we're offering you so much growth that we think it could compensate for that. The second question is, if we assume that we are in 2017, the Gas and Power guy has been very successful again in meeting all his objectives.
If you're standing here, would you say that Gas & Power is contributing to net profit? Would that be around 15% of net profit, 30%? Equal measure for R&M and Chemicals, since this is the new Eni, how do you see it by 2017? Then the last question, it's an easy one. In Mozambique, you've had time to sort of study the field. Would you be concerned, and would you have to watch out what Anadarko is doing? Or is it so big that it really doesn't affect you how they operate and how much they produce? Could you tell us a little bit more about the geology? Is the challenge there the lack of infrastructure? Is the field very easy, high quality? Or what are the challenges that you see now that you know it better? Thank you.
I will try to answer your first two questions, then I will pass it over to Claudio for the geology of Mozambique. He's an expert.
I think we can spend two, three hours talking about that.
He knows much more than me about geology, particularly Mozambique. On dividend yield, let me answer you this way. We do not have any objective of dividend yield, none. Traditionally, if you take the last 10 years, 12 years, we have been among the highest dividend yield in the industry. This means that we have been always careful in rewarding our shareholders at the top of the industry. This is a tradition, and sometimes tradition remain in time. On the second point, 2017, you are asking a very good question. I don't have a precise answer. As I say, I do not have a projection of 2017, the relative things, if everything goes extremely well. What we expect to happen in 2016 at the end of our plan is to stop losing money in Versalis, in chemicals.
Versalis has been a major drainer in Eni in the last 30 years. It has been for a long, long time, a reason of loss, with some years of exception, but in general, this has been the case. We expect R&M to go back to profit. R&M has been traditionally profitable. It has been unprofitable in the last few years, but profitable, and we see no reason why it should not go back to profitability. I think we give a number of EUR 200 million EBIT by 2016. As far as Gas & Power, Gas & Power was the most phenomenal business I've ever seen in my life. Okay? Most phenomenal. We made huge amount of money buying and selling gas. A business which had essentially no investment, was fairly easy because molecules of gas is really a commodity, and still has been very profitable.
Those times are gone forever. We never go back. I remember a time in which we were making €25 per 1,000 cubic meter of gas that we were buying and reselling. This time finished, and will never come back again. Still, we believe that we are in a position, given our extremely strong European position, both as sellers and buyers of gas, to restore profitability. When we give a number of EUR 1.5 billion of EBITDA by 2016, I believe this new number is very reasonable, is more on the conservative side than on the optimistic side. Because we forecast, it can be forecasted also, an improvement of the market, which has been the real thing that nobody has forecasted before. Just to give you a final number.
In 2008, I was making speeches all over Europe saying, just to tell you how wrong we can be, that in 2012, the consumption of gas in Europe was in excess of 600 billion cubic meters. You can go. This year it has been, 2012.
478.
478. I've been wrong of 120 billion cubic meters. It's a combination of difficult conditions in Europe, coal prices collapsing. Coal prices are half what they used to be, and therefore all coal-fired power station in Europe are running at full capacity and not using gas. Of course, there has been also renewables. In total, the world has been moving in the wrong direction for the gas business. We feel all our forecasts are based on this scenario. If the scenario improves, our €1.5 billion of EBITDA by 2016 can be a pessimistic number. Claudio, on geology.
You want to talk only about geology? I joke. About challenges. If we talk about challenges, we talk first geology is not a challenge. It's the best and easier geology, also Paolo can talk about geology of Mozambique, is so easy to describe. We have a thickness of 500 meters, continuity for 25 kilometers, high permeability. You can drill in a deep water well in four weeks. Easy. That is not a challenge. Second point, other possible challenges, Anadarko development. We sign an agreement. This problem is behind us because we sign an agreement with Anadarko. We are going to develop and build the LNG together.
We are going to develop a unique plan of development for unitized area. After that, each of the two company, of the two joint venture, is going to develop its own section of the reservoir in its own area. That is done. We agreed on the first development phase, so infrastructure. We have the land, we bought the land. We are together, the two joint venture, one led by Anadarko and the other led by us. That is done, agreed, signed with them and with the state company. We already start the FEED, so the front engineering phase for a train. We start with four train for 23 million ton per year. That means a total reserve of 24 TCF. Just a small portion of what we can develop. That is done.
We have already feasibility study for the infrastructure. We agreed with the government. There is a strong motivation, not just with Anadarko, especially in the government that wants to develop as soon as possible these fields and these infrastructures. That means road, hospital, a lot of very positive things for the country. I see in front of us a lot of opportunities. All the challenges has been resolved in the last couple of years, working a very good atmosphere with the three components, the government, Anadarko, and ourselves. Anadarko, no issue in front of us.
Great. I think we don't have time for any more questions. We're around for the rest of the afternoon. Feel free to ask us. Ladies and gentlemen, I think we're wrapping this up. Thank you for