Good afternoon, ladies and gentlemen, and welcome to Eni's strategy presentation. For the duration of the call, you will be in listen-only mode. However, at the end of the call, you have the opportunity to ask questions. I'm now handing you over to host to begin today's conference call. Thank you.
Good afternoon, ladies and gentlemen, and welcome to our strategy presentation. This afternoon, I will give you an update on our prospects and targets in each of our main divisions. Before we do that, I would like to highlight how Eni has consolidated its position over the past years and why we are now about to enter a period of rapid growth, which will last not just for the next four years, but for the next decade. In E&P, the restart of our activities in Libya is leading to a fast recovery in our 2012 production. In 2011, we have also made significant progress on key projects, including the FIDs of giant fields in Venezuela and Russia, adding certainty and visibility to our near-term growth prospects.
The key reason why Eni is stronger now than a year ago is the success of our exploration in Norway, West Africa, and Mozambique, which will drive our strong growth to 2021 and beyond. Turning now to our mid and downstream businesses, over the last year, we have taken further steps to increase our competitiveness in what remains a challenging market context. In gas and power, we have concluded contract renegotiations with two of our main suppliers, Sonatrach and Gazprom. We will leverage on our improved cost and flexibility to continue to build our European market footprint, a strategy which will position us well to recover profitability as the market tightens. In R&M and chemicals, we have further streamlined our operations and have targeted additional cost savings and optimizations in each business. In chemicals in particular, we are also targeting a number of initiatives which will significantly improve our competitiveness.
Let me now take you through our strategy and targets in more detail. In E&P, our consistent track record of exploration success over the past year is the key driver of our growth. While 2011 has been an extraordinary year in terms of the size and potential of our new discoveries, it is not an outlier in terms of results. Over the past four years, we have discovered around 4 billion BOE of new resources, almost double our accumulated production of 2.5 billion BOE, with a progressive strengthening of our resource base to 32 billion BOE. Meanwhile, with unit exploration costs of around $1.7 per barrel over the past four years, our exploration success supports our capacity to deliver sustainable returns on new projects under almost any oil price scenario and an IRR in excess of 20% at our planned scenario of $90 for 2012 and 2013 and $85 thereafter.
Our consistent performance confirms the effectiveness of our exploration strategy with this focus on proven basins and the select number of high-potential frontier basins. Building on this success over the next four years, we will increase our exploration efforts to further strengthen the basis of our long-term growth. Let's now take a closer look at our upstream growth profile. Between now and 2015, we will add around 700,000 BOE per day of new production through over 60 major startups, including three of our fields in the Yamal Peninsula in Siberia, projects in Norway, Perla and Junin 5 in Venezuela, Block 15/06 in Angola, and of course, Kashagan, which we are on track to start up by the end of 2012.
Of the total new production which will come on stream by 2015, around 70% comes from exploration, while the remaining 30% comes from the acquisition of underdeveloped resources, in particular our fields in the Yamal Peninsula and Junin 5. This solid pipeline of projects will lead to average production growth of at least 3% a year to 2015 at our planned scenario of $90 per barrel for 2012 and 2013 and $85 per barrel thereafter, and normalizing 2011 production for the Libya impact. Increased scale and the focus on oil compared to gas over the planned period will drive an increase in cash flow per barrel of above 10% to 2015. Looking beyond 2015, following the discovery in Mozambique, we have raised our long-term growth target from 2%- 3% a year.
Africa will continue to be the backbone of our production and growth in the next 10 years, driven by growth in Angola, the startup of Mozambique expected by 2018, and further exploration potential in existing and new countries, including Ghana and Togo. Meanwhile, in North Africa, production will continue to be resilient with very low natural decline. Our other key growth hubs will be Russia, where between 2015 and 2021, we will start up two more Yamal giants in the same peninsula, where we will start the first Tambey project in 2012. Kazakhstan with the ramp-up of Kashagan, and further potential from our development of Karachaganak. Thirdly, Venezuela, where the full-field development of Perla and Junin 5 will contribute around 180,000 barrels per day of production by 2021.
In Europe and North America, we will see a broadly unchanged production level with high natural decline compensated by new projects, in particular the Skrugard and Harvey's startups in the Barents Sea, which will contribute around 70,000 barrels per day by 2021. All of this adds up to the strongest project pipeline in our history. Claudio will give you some additional detail later on this afternoon. Given the breadth of the portfolio, we will also organize a specific upstream seminar in the early autumn. Let's now turn to gas and power. The timing and terms of the disposal of our stake in SNAM will be addressed later in this presentation, and I'm sure in the Q&A.
However, I would like to take this opportunity to highlight how the perimeter of our gas and power division is going to change following the consolidation of SNAM and of our interests in international pipelines TAG, TENP, and Transitgas. The resulting business will be made up of two main parts. The first is a semi-regulated business, which is composed of our other international pipelines and some local distribution. This part of gas and power, which in 2011 accounted for around €600 million of pro forma EBITDA, will provide steady profitability over the coming years. The second is our gas and power marketing business, which has a strong and diversified portfolio of long-term gas supply contracts, power generation capacity of around 5.5 gigawatts, and a leading position in the European gas market.
This is the portion of our gas and power which has been affected by the negative market environment, including the continued availability of lower-priced LNG spot cargoes and a significant fall in demand, in particular in the second half of 2011. In this difficult and volatile market, the key issue is supply. Long-term contracts are essential to guarantee stable supplies to our customers, but they also need to be different from what they used to be. The price needs to be competitive with spot gas. Volumes need to offer the flexibility to cope with demand volatility, and terms need to adapt when market conditions change. These are the pillars along which we have renegotiated with the Libyan NOC in 2010, with Sonatrach in 2011, and with Gazprom in 2012.
We will continue to work on improving the competitiveness of our supply portfolio, opening talks with Statoil in the second part of this year. Meanwhile, our improved cost position will sustain growth and consolidate our position in European retail on the back of over 1 million net new clients added in 2011. Over the past year, we have also worked to enhance our trading capability. Trading is here in London. The office is next to this one. The people here are in close contact with all our divisions to capture the benefits of market volatility and price differentials in different markets. While we expect that the current market weakness will continue to put pressure on our merchant business in the first part of the planned period, we are confident that from 2014-2015 onwards, the European gas market will tighten again.
On the demand front, we see a recovery and then long-term growth in volumes driven by economic development and fuel switching to gas in line with the European objectives of reducing CO2 emissions. In total, we expect EU demand to increase from around 500 BCM to over 560 BCM by 2015 and close to 600 BCM if we look forward to 2020. At the same time, we see European supply tightening. Domestic gas production will decline from the current 173 BCM by around 3% a year to 156 by 2015 and 130 by 2020. LNG imports will level off after the peak in 2011, with capacity growth being absorbed by strong demand in the Far East and Latin America. Traditional European suppliers, in particular in Northern Africa, will struggle to increase exports because of strong domestic demand.
In this context, our diversified long-term supply portfolio, our increased equity gap, and our market leadership in key European countries will be significant competitive advantages, leading to growing profitability in gas and power. Turning now to R&M, our refining business continues to face a difficult environment with stable or declining demand for products and persistent overcapacity, especially in our core Mediterranean market. We expect the scenario in Europe to show limited improvements from now to 2015. Timber refineries will likely come under pressure from tightening product quality regulations, driving a 15% reduction in refining capacity and a modest improvement in refining margins. In this context, our strategy to return to profitability is fully based on self-help measures.
We are working to support margins through the full exploitation of conversion capacity with the startup of our EST plant in San Lazzaro and extensive integration of our refining system, greater supply flexibility to take advantage of opportunities in the pricing of different crudes, and enhanced integrated trading operations. We will continue to focus on cost reductions and, in particular, on energy savings and labor and maintenance costs. Meanwhile, we will consolidate the profitability of our marketing business, leveraging on the rebranding of our network, the full automation of stations, and the opportunity to expand non-oil activities offered by the liberalization process in Italy. Overall, these actions will improve refining and marketing results by around €550 million by 2015, at the same scenario we experienced in 2011, with over €400 million coming from the refining segment.
Now, while we do not usually spend much time on Eni's chemical business, this year I would like to give you a little more detail because we have launched a turnaround strategy. This business, accounting for around €2 billion or 2.5% of our capital employed, has always been weak with a fragmented industrial footprint. On top of this, in recent years, the European chemical sector has suffered from increasing price pressure on base chemicals, with ethylene production costs a multiple of those in the Middle East. As a result, despite cumulated efficiency gains of €360 million between 2006 and 2011, in positive market conditions, when everything goes well, our chemical business makes limited profits. While in negative market cycles, it absorbs cash. To tackle this issue, we have devised a strategy based on three main pillars.
The first is the refocusing of the business, increasing our presence in added-value products such as elastomers, styrenics, resins, and EVA, where we have a leading market position in Europe. Demand for these products is expected to grow in coming years, and margins are resilient even at higher feedstock prices. In this segment, we target an increase in sales of 50% to 2015, by which time added-value products will make up over 40% of our revenues. The second pillar of our strategy is international expansion, building a presence in emerging markets, especially in Asia and Latin America, through licensing agreements, production alliances, and joint ventures. We target a doubling of extra European sales to around €700 million by 2015. The third is further efficiency and capacity rationalization.
As energy saving and further integration of our production cycles, we are planning to close or convert loss-making sites, cutting our polyethylene capacity by 20%, and supporting our refocusing on added-value products. We have already begun to implement this approach with a project to build an innovative bio-based chemical complex on the site of a structurally loss-making basic chemical plant in Sardinia. All of these actions will deliver over €400 million of additional EBIT by 2015 at the scenario, the bad scenario we experienced in 2011. This efficient and refocused business, with its exposure to more profitable and defendable markets, will be able to better offset negative cycles and capture the benefits of the positive swings. To reflect the strategy, the new strategy, we have renamed the business Versalis.
It will be expertly led by Daniele Ferrari, who is here at the end of the table, who joins us with 25 years of experience at ICI Enhancement and who will be happy to answer your questions during the Q&A session. Turning now to our listed non-core assets, over the past year, we have progressed in our strategy of unlocking value. With regards to our 53% stake in SNAM, currently worth almost €7 billion at market value, our exit will be regulated through a government decree to be issued by the end of May, the end of this May, and will be completed at the latest by September 2013. In terms of how this separation will occur, we do not yet have clarity on the contents of the decree. We will, of course, update the market when we do.
However, the position of Eni's board is that the disposal process will need to meet three criteria. First, it will need to be friendly to Eni's shareholders, by which I mean a deal which recognizes the full value of our stake in SNAM. Secondly, it will need to protect the interests of SNAM shareholders by limiting the possible overhang on SNAM shares. Thirdly, it will need to strengthen Eni's balance sheet in view of our extraordinary growth prospects building on exceptional exploration success. With regards to our stake in GALP, this is not the first time we talk about GALP. We reiterate that being a co-controlling shareholder in a listed company where much of the value is in a minority holding is not part of our strategic priorities. That said, we are in no rush to sell.
This is an asset with great potential, particularly with regards to its position in Brazil and now in Mozambique together with us. We are pleased that the market is starting to value its growth prospects. In this context, we are talking to our partners to find an agreed disposal option within our shareholder agreement, which expires in March 2014. This concludes my overview of Eni's strategy and targets, and I will now hand you over to Claudio for a closer look at E&P.
Thank you, Paolo. Good afternoon, ladies and gentlemen. Let me start by reinforcing our priorities and our strategic drivers. Our focus is on exploration and the timely conversion of resources into reserves and production, and at the same time, on fighting depletion and enhancing the recovery factor in the existing field through continuous reservoir management. The key to meeting these goals and mitigating risks is the development and consolidation of critical skills and technologies, which we leverage through increasing operatorship. We remain highly focused on strong HEC performance. This year, we registered a further improvement in our safety indices. Our LTI index was down by 40% compared to the average of the previous four years. On drilling, despite the significant increase in the number of operated wells, which have nearly doubled since 2005, we recorded zero blowouts in the last eight years. Continuous improvement on safety is our first priority.
We put strong commitment on initiatives to promote individual awareness on safety, including training and a strict follow-up on execution. We are delivering more than 200,000 hours per year of training, drills, simulation, and assessment on our people HEC capabilities. Now, I will give you some detail on our growth strategy. I will focus first on exploration, where our recent successes and high potential exploration assets are the foundation of organic growth for the next decade and beyond. I will update you on our main development project. Last year was very positive for our exploration. We drilled 56 wells, of which about 80% were successful, and we have added 1.1 billion barrels of new resources. We also continue to rejuvenate our portfolio by adding new acreage, notably in Indonesia, Australia, and Angola. Looking forward to the next four years, our strategic guidelines remain unchanged.
We will continue to focus on assets with high materiality and fast time to market, concentrating on places where we have experience and good knowledge of the geological model. These include West Africa teams such as Transform Margin in Ghana and Togo and the Pre-Salt in Angola, Congo, and DRC. The East African territory plays the balance sheet. We are also renewing our portfolio in new basins close to areas with high demand growth. Our exploration portfolio will continue to deliver industry-leading results. Over the next four years, we aim to discover about 1 billion barrels of oil equivalent resources per year at an average unit exploration cost of $2 per barrel. Let's take a closer look at three of our most promising exploration targets.
The first is the Barents Sea, where Eni with Statoil is the only operator present in all three large oil discoveries in Goliat, Kruger, and Harveys. The second, Skrugard, a prized oil well found about 80 meters over the carbon column, confirming a world-class discovery, and the Harvey and Skrugard complex accounts today for more than 500 million barrels of recoverable resources. Following these major successes, we believe we have cracked the geological code in this part of the basin and are confident in a significant resource upside. We will unlock this through an aggressive exploration program with at least eight further wells in the next four years and a €220 million investment. We will maintain our leadership in this exciting exploration frontier, leveraging on our strong asset base. Let's now turn to Mozambique. Mamba, in Area 4 of Rovuma Basin, is a transformational discovery.
We estimate the resources found with the first two wells at about 30 TCF of gas in place, or 5.4 billion barrels of oil equivalent. The test on Mamba North One, the first performed in the area, confirmed excellent reservoir and well production characteristics. In a final completion configuration, production per well is expected to reach over 140 million cubic feet a day, approximately 25,000 barrels per day. The gas is high quality, lean, and without sour components. The resources we identify are sufficient for a first stage of development. The first step will be the unitization with Area I structures and then a definition of a common plan of development. To assess the exploration upside, we plan to drill six to eight further wells and acquire further seismic data in the area of Mamba, investing €400 million in the next couple of years.
The objective is to validate an additional four or five structures, most of which are entirely in Area IV. Now some details on the Pacific basin. In Australia and Indonesia, building on 700 million barrels already discovered, we are expanding our portfolio and fast-tracking the evaluation of recently acquired exploration assets, including the Arguni I block and North Ganal in Indonesia and Evans Shoal, Heron, and Blackwood in Australia offshore. Our work program in the area over the next four years encompasses 24 wells and €300 million of CAPEX, with the objective of fast-tracking development with synergies to existing LNG facilities. A good example of this approach is the extended Junk Creek area, which has reached 4 TCF of gas in place through the Junk Creek and Junk Creek Northeast I discoveries. The development plan was approved by local authorities at the end of last year.
We foresee the FID by 2013, and we target the startup by 2016. As a result of the sizable blocks already secured, over the next four years, we will increase our level of activity to 300 wells from the 240 scheduled in the previous plan. We will increase our exploration investment to €5.5 billion. About 20% of this CAPEX will be dedicated to appraisal campaigns to expedite the time to market of the significant discoveries. In geographical terms, 60% of the CAPEX will be concentrated in Africa, which will continue to provide the backbone of our production in the future. We are also increasing our exposure to Far East, which will account for about 10%. Europe will absorb about 15%, many focused on Norway. Compared to our previous plan, we have increased the share of exploration CAPEX devoted to frontier areas from 30%- 40%.
Our successful track record on exploration will further consolidate our resource base in the long term. However, discovering resources is not the only challenge of the industry. The second, and possibly the most complex challenge nowadays, is converting resources into reserves and then production. Achieving this in a timely manner with an efficient use of capital and with a strong technical focus to guarantee efficient and reliable production over time is critical. Our objective is to achieve these goals not just through relentless attention in day-by-day activity, but also through specific initiatives. We have fine-tuned our processes and organization to constantly monitor the status and value of our resources in the different phases of conversion. For instance, we created a dedicated function and allocated budget to accelerate the appraisal of discovered resources. We monitor the status of silent resources and the bottleneck their development.
We have identified specific KPIs to monitor resources conversion. Through these actions, we will be able to develop more than 90% of the exploration successes of the last three years within eight years of the discovery. Our focus on exploration and time to market translates into a robust pipeline of projects and startups within the plan and beyond, which underpins our goals of long-term production, growth of over 2 million barrels per day by 2015 and around 2.4 million barrels per day by 2021 at $85 per barrel. Looking at our four-year plan in more detail, startups will contribute around 700,000 barrels per day of new production by 2015. Of this, 80% will come from giant fields with long-lasting plateau. Approximately 75% is already sanctioned, and most of it will be operated directly by us.
The pipeline of projects is geographically diversified, with 20% of the new production coming from development in OECD countries and 30% from Russia and the Caspian area. However, while our production is geographically diversified, it is also focused on a number of key hubs with synergies in terms of geological and local expertise, infrastructure, and relationship with local communities, which will give a material contribution to long-term production. I will now give you an update on the main development hubs. The first is the Yamal hub in Russia, where we have five giant gas and condensate fields to develop. Here, we finalized our gas sales agreement and took the final investment decision on the Tambeyskoye field. First phase development progress in February was 91.5%, with the drilling campaign ongoing. First gas is confirmed by the middle of this year.
In Q4 last year, we also took FID for the Urengoyskoye field. Drilling activities have started. Startup is expected in 2014. Activities are progressing also on the Yaroyakhinskoye field, where production startups are forecast by the end of the year, while gas production will start up in 2014. Lastly, the Severo field will be in production by the end of 2015, and activities are progressing for the definition of the field development plan. Overall, our Yamal hub provides over 120,000 barrels per day of production by 2015, and we confirm our expectation of long-term plateau production of around 200,000 barrels per day. In the Barents Sea, besides exploration activity, the Goliat project is moving forward. Overall progress at the end of January was 38%, with production startup confirmed by Q4 2013. Last year, we installed the HAT subsea template.
This year, we will start the drilling campaign with the Scarabeo HAT. Norway will contribute around 160,000 barrels per day to production by 2015 and around 200,000 barrels per day in the long term. Our Kazakhstan hub has two main projects, Kashagan and Karachaganak. On Kashagan, we are getting close to the commercial production of the first phase. We are currently undergoing mechanical completion and commissioning. The overall physical progress to reach commercial production was 99% at the end of February. The first 16 wells required for the initial stage of production are already drilled and ready to produce. Four further wells will be made available for production during summer. Startup is expected by the end of the year with a rate of 75,000 barrels per day and a gradual ramp-up to a capacity of 370,000 barrels per day by early 2014.
Overall, Kazakhstan will provide 170,000 barrels per day of production by 2015 and around 200,000 barrels per day by 2021. In Venezuela, our Perla and Junin 5 projects are progressing well. With regards to Perla, in December, we finalized the commercial agreement and took FID for phase one, which will reach production of 300 million standard cubic feet a day of gas by 2014. Startup is expected by next year. Our priority for the Perla gas is the domestic market. However, we are also evaluating export options in coordination with PDVSA. For Junin 5, startup is expected by 2014, and we are working with PDVSA to bring forward early production to the end of this year using existing PDVSA facilities. Overall, our Venezuela hub will provide 65,000 barrels per day of production by 2015 and will have a long-term plateau of 180,000 barrels per day.
Finally, Sub-Saharan Africa is an extremely important hub. Apart from Mozambique, which we have already discussed, the key projects for needed long-term growth are Block 15/06 in Angola, where we have started the execution phase for the West Hub and drilled the first four wells, OPL 245 in Nigeria, for which we led an FID by 2014, and gas and condensate projects related to Sankofa and Gye Nyame discovery in Ghana, for which we are evaluating both domestic and export options. Overall, we expect the Sub-Saharan to provide 500,000 barrels per day of production by 2015 and something in the region of 750,000 barrels per day in the longer term, with a sizable contribution from Mozambique. These enhanced exploration and development plans will be fueled by investment of almost €45 billion over the next four years, an increase of 14% on the last plan.
The increase is largely driven by Mozambique, which between exploration and development accounts for over €3 billion of CAPEX and projects in the Barents Sea. It also reflects our increasing exploration activity in Ghana and Indonesia and the new development of OPL 245 in Nigeria and Adria in the Gulf of Mexico. These CAPEX will generate strong returns going forward. The break-even price for our overall portfolio of ongoing projects is $45 per barrel, while the internal rate of return of our startups over the next four years is more than 20% at our planned scenario. As a final and essential remark, let me summarize the expected results of our program of activities in terms of production and value. First, we will deliver sustainable production growth at the high end of the industry. Our growth to 2015 will be at least 3% a year on average.
This target includes contingency and asset rationalization of over 200,000 barrels per day, higher than ever before. Our growth will be resilient in the context of higher than forecast oil prices. At $100 per barrel, we will deliver growth in the region of 3% a year on average to 2015, compared to our previous planned growth rate of 2% to 2014 at the same scenario. Secondly, as well as growth, we will generate value. Our cash flow per barrel is already one of the highest in the industry, underpinned by an efficient cost position. Last year, we had one of the best unit exploration costs in the industry, $1.2 per barrel, and down from the last three years' average of $1.9 per barrel. The same applies to OPEX, where between 2009 and 2011, we registered an industry-leading average of $6.3 per barrel.
Starting from this excellent base, the scale and characteristics of our project will enable us to grow cash flow per barrel even further at a flat $85 barrel scenario. To sum up, our exploration results underpin a project portfolio which is the strongest in the last decade. We will deliver the value of this portfolio leveraging on operatorship, development and deployment of new technologies, and continue focus on time to market. Thank you for your attention. I will now hand over to Umberto.
As Paolo Scaroni mentioned, the European gas market will remain complex in the short term, but we expect to gradually see it rebalancing and improving in the medium and long term. Let's look at the short term first. In terms of supply, over the next 12- 24 months, we expect a slight increase compared to last year. While we do not see growth in the LNG import from Qatar since it has already reached its planned production target, gas supply will increase due to the resumption of Green Stream. Furthermore, additional volume might be imported via the new North Stream capacity. This increase in imports will be partially compensated by the decrease in European domestic production, which will reduce supply by around 10 BCM over the next two years.
Meanwhile, demand growth is expected to be sluggish owing to the weak economic situation, which will particularly impact industrial gas demand and increasing competition from the renewable power generation tools. The combination of slightly higher supply and sluggish demand will result in continuing oversupply to the European market. Despite the benefit from renegotiation, in the short term, we therefore expect spot gas to remain at a discount to long-term oil link supply, resulting in continuing competitive pressure on the market. Looking beyond the next 12- 24 months, however, we expect the European market to rebalance and then show further improvements. This will be driven by three key trends. The first one is demand growth, especially in the Pacific area, where between now and 2015, consumption will increase by 16% or around 90 BCM.
This will largely absorb the new LNG production coming on stream in the region and also will attract some of the Qatari supply, which is currently being delivered to Europe. Furthermore, South America and the Middle East will see an increase in demand for spot LNG cargoes, which also absorb some of the supply from Europe. The second one is that North America will continue to be an island on gas terms. The United States' domestic production will grow, but we expect exports to be limited and subject to regulatory constraints, as the U.S. government may not want to encourage an increase in domestic gas prices. The third trend is rising import requirements in Europe, which will increase by almost 80 BCM to 2015 through the combination of growing demand and declining domestic production.
Given the marginal expected contribution of European shale gas by that time and the tightening of the LNG market, we expect additional import requirements to be mainly satisfied by pipeline gas under the long-term contracts. Over the next four years, we also expect the internal European gas market to become more integrated thanks to the construction of new interconnections. Easier gas circulation will create additional commercial and trading opportunities for companies like Eni with diversified supply contracts and a strong market position. Moving on to our strategy, supply is the key factor to cope with short-term market volatility and to increase profitability when the European market tightens. It has first to be competitive with spot price, then to be flexible on takeoff volumes, and third, to give both suppliers and buyers the option to renegotiate more frequently if required by market conditions.
We have already made good progress on this front. In the last two years, we have closed contracts renegotiation with Libyan NOC, with Sonatrach, and in the recent weeks with Gazprom, which between them accounts for almost 70% of our supply portfolio. Looking forward, we will continue to work on the competitiveness and market reflectivity of our portfolio, opening negotiation with Statoil in the second part of this year. As a result of these actions, we are now in a better position to pursue our strategy. Despite the current market turbulence, we will continue to consolidate our market position and gradually we recover profitability as the market tightens. Let me now take you through the key commercial strategy which will drive safe growth over the coming year. We have two distinct commercial objectives.
The first is to consolidate our leading European position in the business gas market, where we have a well-balanced portfolio in terms of geographies, customer segment, and contract duration. Over the planned period, we will increase our sales to industrial, power gen, and resellers by 13 billion cubic meters. We will do this through our strong commercial platform in the largest consuming countries like Italy, France, Germany, U.K., Spain, and Belgium, and in our new target market, the Netherlands, Austria, and Hungary. In particular, our growth will be driven by our reliable and increasingly competitive supply portfolio and our capacity to offer clients tailor-made solutions with a multi-country approach. In doing so, we will leverage on our decades of experience in the gas market to provide a wide range of services, including risk management and transport and storage contracts.
Our second commercial objective is to increase our penetration in the European retail segment, increasing our customer base by almost 30% in the next four years. We are already strengthening our position in this segment. In fact, last year in Italy, we added 500,000 new contracts through our dual fuel offer and innovative sales channels. In Europe, with the acquisition of Altergas and Nuon, we can now count on a resilient customer base in France and Belgium, highly complementary to our operation in the business segments in those countries. Looking forward, we will continue to grow in the European retail segment using our valuable experience gained in the Italian retail market, our high-quality service and customer care, and our multi-channel sales platform stemming from Eni branded energy stores, local agency, online marketing, and web.
The combination of our market view and our actions underpins our target of growing profitability to more satisfactory levels over the next four years. Focusing on marketing and international transport, which in 2011 reported €1 billion of pro forma adjusted EBITDA, we will see an increase in 2012, driven by the recovery in Libyan supply and the benefit from the closure of the renegotiation with Gazprom, of which a part relates to 2011. However, our underlying marketing business will continue to face market pressure. Looking further ahead, the progressive tightening of the European market will result in further growth in our sales and margins. We will also leverage on the flexibility of our portfolio to capture trading opportunities in Europe and in the Far East. Thank you for your attention. I will now hand you over to Sandro for the financial outlook.
Thank you, Umberto. Before we move on to our CAPEX and efficiency plans, I will take you through the financial impacts of the consolidation of SNAM, which will occur before September 13. While SNAM's leverage is relatively low compared to its regulated peers, it is relatively high compared to the core Eni oil and gas activities. That means that the consolidation, a process which would see Eni accompany SNAM to gradually reach financial independence, would by itself lower its gearing. Indeed, stripping out the €11.2 billion of debts attributable to SNAM, Eni's 2011 debt-to-equity ratio declines from 46%- 30%. If, as well as the consolidation of the debt, one assumes a cash inflow broadly in line with the current market value of our 53% stake in SNAM, Eni's leverage drops to below 20%.
The consolidation of SNAM would also boost Eni's returns on capital invested from the reported year-end level of 9.8%- 10.4% on a see-through basis and to 11.4%, factoring in a cash inflow equal to SNAM's market value. Let's move on to our CAPEX plan. Our growth over the next four years will be fueled by €59.6 billion of investments, of which €6.2 billion pertains to SNAM and will therefore be de-consolidated within the planned period. On a de-consolidated basis, this represents an increase of €6.4 billion compared to last year's plan. This increase is driven by our enhanced exploration and development plan in E&P and, in particular, the new attractive opportunities we identified last year, including a first tranche of the Mamba project and giant developments in Nigeria, Indonesia, and the Barents Sea.
Two-thirds of the planned CAPEX for the next four years is already committed, increasing visibility on cost and delivery of our project pipeline. With regard to our other businesses, we have adopted a more selective investment approach, with CAPEX largely concentrated on efficiency programs and refocusing of our portfolios on the most attractive segments. In gas and power, assuming the same perimeter we have today, so including SNAM, planned investment will mainly relate to regulated businesses, which, as you know, have guaranteed return. Marketing will account for about €1 billion of CAPEX, mostly in power generation, to increase flexibility and maximize margins. In R&M, we plan to invest about €2.8 billion in line with the previous plan, but with decreasing expenditures on refining.
By the end of this year, we will complete the main development project underway in R&M, the EST plant in San Lazzaro, further improving the complexity of our system. Remaining CAPEX will include the rationalization of logistic infrastructures, the rebranding of our service stations, and non-oil development. Finally, investment in chemicals will be mainly dedicated to new initiatives expected to boost organic growth in the most profitable segments. These projects represent two-thirds of total expenditures, with an attractive internal rate of return of over 20%. On top of the consolidated €1.6 billion attributable to chemical in CAPEX, we will also invest around €200 million in our new bio-based chemical plant project in Sardinia. Efficiency will continue to be an important part of our strategy.
Since the beginning of the program in 2006, we have delivered over €3.1 billion in cost savings by streamlining our processes and driving continuous improvement in our operations. Savings achieved in 2011 amounted to over €600 million, half of which came from enhanced efficiency at the corporate level. Our new plan has once again increased our target for cost savings, now expected to be €5 billion in total for the 2004-2015 period. This will be achieved through procurement and logistic optimization, energy saving, and increased labor efficiencies. New projects and our strong focus on efficiency will support our cash flow generation over the next four years.
At our planned scenario of $90 per barrel oil in 2012-2013 and $85 per barrel in the following two years, our strong cash flow from operations will more than fund our increased investments and reduce net debt to well below 40% of equity by 2015. This target is, of course, at a constant perimeter, which means excluding the reduction of leverage which would occur as a result of potential disposals and the consolidation of SNAM. Meanwhile, exiting SNAM will not have a significant impact on Eni's organic free cash flow, as SNAM has historically reinvested the entirety of its cash flow from operation to fund CAPEX and is expected to continue to do so. As a result, our dividend allocation will not change owing to the consolidation of SNAM.
Under our planned scenario, we confirm the sustainability of our dividend policy of growth in line with inflation, which aims to preserve the real value of the remuneration to shareholders. Thank you for your attention. Now I will hand you over to Paolo for his closing remarks.
Thank you, Sandro. In conclusion, through a combination of exploration success in E&P and operational progress in each division, we are now in a better position than ever before to deliver long-term growth and value. E&P will continue to be the main driver of our business, building organic growth from exploration success. We are entering a period of accelerating growth, and our track record of consistently delivering around 1 billion BOE of new resources every year underpins production potential of over 2.5 million BOE per day, supporting our growth targets to 2021 and beyond.
In gas and power, we have challenging short-term market conditions to contend with. Our progress on the cost and flexibility of our supply improves our ability to grow in key markets and segments, and we will reap the benefit of these actions as the European market tightens in the medium term. In R&M, our focus on efficiency in refining and consolidation of our position in marketing will return our operations to profitability. In our chemical business, we'll push a turnaround strategy with a focus on added value products and high-growth markets. On top of our robust business objectives, we have the potential to unlock value through the disposal of our non-core listed assets. While disposal options and timings are not yet finalized, monetizing our stakes in GALP and SNAM would also significantly strengthen our balance sheet.
We consider that a strong financial structure is appropriate to a business portfolio more focused on E&P. It will give us additional flexibility on our major development projects. With a high potential exploration campaign ahead, we will be able to take full advantage of new organic growth opportunities with attractive returns. What will not change is our prudent approach to M&A, we continue to be focused on bringing our resources to reserves and production. Taken together, all these actions and opportunities give Eni a clear roadmap to growth and value creation in the year ahead. Thank you for your attention. We will now be pleased to answer your questions. Camilla.
Hi, everybody. We're going to take some questions from the floor and then some questions from the call. If you wouldn't mind putting your hand up if you want to ask a question and then stating your name and surname.
Hi. I'm Nuno Briticunha from Spirit Centre Investment Bank, and I had a question for Mr. Scaroni on the GALP stake. Given what we've seen in the press over the last couple of weeks that Americo Amorim has been negotiating with Eni for an acquisition of half of the stake, my question is, if there's an agreement signed, what would you be willing to do with the other half of the stake? Would you be willing to place this in the market, or would you? What would be your decision on that? Thanks.
Okay, do we answer every question?
Yes.
We've had. Yes, l et me, since I am expecting further questions on GALP, give you the full picture for a second. Our stake is worth something in between €3.5 billion and €4 billion. Until 2014, there is no possibility for us of selling those shares, probably not even one of those shares.
Correct.
Not even one, without the agreement of Amorim Energia and the government, the government being the Caixa de Depósitos. These kinds of questions of yours, you should ask them rather than us. In the sense that if they would agree for us to sell 15% here, 15% there, 10%, we probably would do it. The point is that we have to reach an agreement with three partners in order to divest before 2014. If you want my view, I believe that probably 2014 is very far to reach a solution, and I'm fairly confident that we will find a solution for these divestments before that time. I believe that this is probably more likely than not. Still, we don't have an agreement which will allow us to divest from our stake. On the other hand, as I reiterate, I'm not particularly in a hurry.
This, at the end of the day, is our business. Most of the value of GALP is running inside our E&P business, and particularly Brazil, and now Mozambique. Now, Mozambique, as you have heard today, we consider that Mozambique has a lot of value, and GALP has 10% of it. The market is partially recognizing value. Share price is doing reasonably well. We believe that there is much more potential than that. We are not really pressed to find a solution tomorrow rather than six months from now. Okay?
Alejandro.
Good afternoon. Alejandro Demichellis f rom Merrill Lynch. Two questions if I may. The first one is on the 2015 strategic plan. You will probably divest both SNAM and GALP. What would be the plan to do with those proceeds? That's question number one. Question number two is, you've given us the 2021 growth target on the E&P business for 30%. What is the level of CapEx that we should be assuming that would be enough to sustain that growth?
Look, on the first question, our first idea about what to do with the proceeds is to pay back debt. We love the idea of paying back debt. We think that a company like ours, which is involved in huge projects, which is investing a lot in exploration, and therefore more projects ahead, has to have a very strong balance sheet. This is the general view. They say the more we make exploration, the more we make discoveries, the more we make development, the more we need a strong balance sheet. That is the general view. Of course, we have been confirming our dividend policy even without NAM. I think this was the message that you received. Of course, even without GALP. These two things do not influence our dividend policy.
Therefore, as far as we can see, that is 2015, we see a world in which Eni will need a strong balance sheet in order to develop its very exciting projects all over the world. In terms of CapEx, I cannot give you a precise figure because we have not developed the 2021.
No, but the CapEx, we are talking specifically. We believe, generally speaking, that it would be in the region where we are today. We don't have every CapEx. I don't know if you have a different view, Claudio.
No, no. I think that we can say that it will be a little bit more than what we are spending now. It's in the range of $12 billion as an average. That is more or less the, t hat's all. Not big increments. Also, because there are some projects that are slowing down, another project entering, so that is more or less.
Yes, you see, we will not have SNAM, and we will have probably some more E&P. In total, we will be in the region where we are today.
Yeah.
David Trenchard from Knight Vinke. As you know, we are long-term shareholders in Eni, and this is a question for Mr. Scaroni. Over the last few days, there have been suggestions in the Italian press that Eni shareholders should prefer that Eni sell its shareholdings in SNAM for cash rather than spinning it off, since a spin-off could in some way be less attractive for Eni's shareholders. You yourself, this afternoon, have talked today about monetizing your investment in SNAM. As shareholders of Eni, we'd like to state for the record that Knight Vinke would be indifferent. Each solution results in SNAM's €11 billion or so of debt being deconsolidated, subject only to timing. Eni and indeed Italy are currently both in a sweet spot in that the market is giving you credit for reducing your debt.
Execution in both cases is now critical, and if the market gets the sense that you're dragging your feet, the fall from grace could be quite rapid and quite painful. Can you therefore provide us with the comfort of saying that if the sale of SNAM does not take place by, say, late autumn, that you will in any case proceed with the spin-off?
You are asking the question to the wrong person because spin-off, this is not my decision. It is the decision of the government. You are addressing the question to the wrong person. Let me just add a small detail to what you have been saying. If instead of selling our stake, we would deconsolidate our stake in SNAM, for example, making a dividend in shares to our shareholders of SNAM shares, this will probably cause a downgrading of our company because it is true that we have $12 billion of debt, which we deconsolidate. It is also true that rating agencies know very well that in front of this $12 billion of debt of SNAM, there are revenues regulated, certain, which offset this debt. Just to tell you that the two things are not exactly identical for Eni and for the shareholders of Eni.
Having said that, I will take note of your declaration. As far as the question, address them to the government.
Hi. It's Iain Reid from Jefferies. I want to ask you a question on Mozambique. You said at the fourth quarter results call that you might sell down your 70% stake to something more like 50%. Since then, there's obviously been a bit of bid activity on the other side of the block. I wonder whether that's still your intention. Can you say whether Shell has approached you to potentially buy that 20% you've talked about divesting? You probably won't answer the second one, but maybe the first one would be interesting. Secondly, on Kashagan, now we've got to the end of the long slow process. Can you tell us how much the first phase, the experimental phase, finally cost?
Claudio, I'll answer you the second question about Kashagan. As far as potential divestment from our 70% stake in Mamba in Mozambique, let me just tell you that it's very early days for us to even consider any possibility in this area. It is true that we have been approached by almost every player in the industry who would like to be part of this new frontier for gas in Eastern Africa. That's true. We are still in an exploration phase. We don't really know what we have apart from the 30 TCF that we have been discovering the last few months. Therefore, whatever decision we would like to take, this would be not before I would probably say the end of this year because most of our exploration would be finished by the end of this year, beginning of next year. On Kashagan, Claudio.
On Kashagan. On Kashagan, the direct cost of Kashagan for the experimental phase are in the range of $34 billion against $32.6 billion authorized in 2008. There is an increase of about $2 billion. The direct cost for the development without the GNA, about 4%, 5%.
Any more questions before we close?
Not at the moment. Maybe if there's questions from the call, we could pass on to them now.
This is a message for the person in the audio conference. The Q&A session is open. If you would like to register for your question, please press star followed by one. To cancel the reservation, press star followed by two. Thank you.
No questions from the call. More from the floor, though.
Yes, good afternoon. Roberto Ranieri from Banca Intesa Sanp aolo. A few questions on the Gas and Power division. My first question is, what do you think about the potential process of making available the spare capacity in the import pipelines? If you can, a little bit elaborate on the effect or the impact on the gas and power prices in the Italian market, and if this potential impact is included in your target in the gas division. That's my first question. My second question is on the gas demand as well. You disclosed 18% demand increase all over the period up to 2020. My question is, many operators are saying that in the period 2012- 2015, the gas demand would be very weak. I'm wondering what the demand increase would be all over the planned period. The third question is on the E&P.
If you can disclose some data about the funding and development cost in Mozambique, and if possible, if you have any. I understand that it could be a bit early if you have any recovery ratio on Mozambique. My final question is about the production target in the E&P. Basically, you are saying that 700,000 BOE is the additional production from new discoveries. If my mathematics are not wrong, I understand that 50% of it will be eroded by the depletion rate. My question is, if you are considering something like a disposal of these depleting fields in special purpose companies just to eliminate the tail production. Thanks very much.
Many questions. Let me try to answer one, then I will pass to my colleagues the others. On gas demand, this 18% by 2020 or by 2015, what will happen to demand? To answer your question, we should make some economic forecast in Europe. What we know is that the penetration of gas as a primary source of energy continues to grow. Essentially, in Europe, there is no way to make electricity other than renewables and gas today. Nobody would ever think to build a nuclear power station or a coal-fired power station. If you believe that European industrial activity will grow by 4% per annum, you would expect gas consumption to grow more than that, to grow significantly. If you believe that Europe is going to be in stagnation until 2015, gas demand will remain sluggish.
Our view is that demand for gas will grow, not a lot, but I think we gave you a number of by 2015, how many million cubic meters more, something like 70 billion cubic meters, moving from 500 to 570, if I'm not wrong. That's on the question about demand. On the first question, maybe, Umberto, you want to answer?
One of the articles of the liberalization decree foresees the objective as to reduce cost for industrial customers, gas industrial customers, by increasing the level of import of gas from Northern Europe. This is the objective of the article and implies that we will see some decision about the binding modulation for the residential customer, particularly if you're considering a situation of a very rigid winter. Another aspect that still has to be defined will be at which condition this gas will be made available. This has to be identified, how that will be guaranteed to be at competitive conditions. Market rules. We expect the government to continue on this approach and taking quite rightly a very cautious approach in order not to create a distortion in the market. I have to say that I missed the second part of your question on this subject.
If you could please briefly repeat it.
Yeah, the second part is if this kind of a scenario will make some further pressure on margins, gas margins, and if this scenario is included in your new targets in this 2012-2015 plan?
Okay. Thank you. Yes, it is considered because in our scenario, we have defined a level of criticality of the market continuing for the next two years with a further competition between spot price and the long-term price. Nevertheless, we are imagining a situation that will show some recovery of demand, some tightening of the LNG market that will reduce the spread. Therefore, making less critical as it could look today the fact that there will be more open circulation of gas also coming from the North European hubs.
For Mozambique and for the planning and development cost, what we can say now for Mozambique, we can just talk about the exploration unit cost. That is one that has been very, very low, around $1. For the final development cost of our E&P division is for the four-year plan, $14.5 per barrel. For Mozambique, we cannot say we cannot talk about final development costs because normally, we put all the costs divided by the P1 reserves. For Mozambique, we don't have yet the P1 reserves. We just can't talk about the exploration cost. For the second question about production, in the four-year plan, we have about 40,000 barrels per day disposal. It's true, we are going to dismiss some assets, and these assets mainly in the North Sea. That is more or less what we are going to do at the moment. That is a green plan.
Hi. It's Alastair Simon from Citi. Can I ask three interrelated questions on the downstream, please? Firstly, if you look at previous cost-cutting plans, which have been largely directed to this business, they don't seem to have had much impact on profitability. I just wonder why you think you're going to be able to retain cost savings this time around. Secondly, what do you think will happen to capital employed across downstream, both refining, marketing, and chemicals through the period? Thirdly, I wonder if you could put those together, the capital employed and the cost savings target, in terms of a return on capital employed target.
Of course, your questions are focusing on downstream. In fact, the stories around R&M and chemicals are somewhat different, and they probably deserve different questions. Let me first deal with the issue around chemicals. I will say a few words about the story of our chemical business, and I will then hand it over to Daniele, who will talk more about the future of the business. The story of our chemical business is all around the fact that when we were 100% owned by the Italian government, we have received as a gift, not really the kind of gift you would like to have, all the companies which went bust in Italy doing the chemical businesses. We have received, I can say, hundreds of plants all over the country. Some of them closed. All of them are in Sindier.
You know that we have this bad company, which is making an activity of, let's say, depolluting the fields. The ongoing ones went into polymery. This business was, if I may simplify, from my point of view, running systematically six or seven percentage points of EBIT below its competitors as a result of being wrong locations, small plants. You know, the fact that nobody has decided anything about them. They just arrived. As a result, when everything was fantastic, we were making some money. When everything was bad, we were losing a lot of money. This has been true for many, many years, probably since the beginning. The whole strategy we had was, let's cut down this disaster. This was the idea. No, let's close plants, close pieces of plants, reduce, reduce, reduce.
Of course, you can imagine how difficult it is in Italy to close down plants, particularly in southern Italy, because most of these plants are located in Sicily and Sardinia, which adds to the problem. This strategy has been followed until, let's say, a couple of years ago when we decided that in order to go further, we needed to have a different idea because otherwise, we were stuck with this perpetual problem. We hired who has been, who's an expert and is bringing new fresh air to our thinking in chemicals. He has been working on a plan which at least convinced me. I hope it will convince you as well. It has been very convincing for me, which maybe in five minutes you would like to.
Thank you very much for pitching the situation so well. I think what Paolo was saying is that we didn't decide to have the chemical business in such a shape that we have it today. That's the essence. We've got to do something different from the past, which is not fixing problems and efficiency, but we need to reconfigure the business completely. Play on our strengths. We do have strengths. We have critical mass. We have good technologies. We have excellent reputation. We'll just change the strategy and play on the added value power that we can make and try to enlarge that part from 30% into 70, 80%. This would be through JVs, going back to Asian or Latin American markets, following our customer base, which are developing their technology across that territory. This is the way that we will deploy the capital in the future.
Green chemical project to replace obsolete petrochemical sites technology, geographical expansion. Reshaping our portfolio. We will not throw away the $360 million we built on efficiency. This has to continue to be part of our plan because of the economics of the site where we are located. We will build on that to make it more profitable in the future. I hope I answered your question.
Let's move into refining. Since most of your questions are around financial, we'll ask Sandro to answer.
Yes. As already anticipated during the presentation, we are committed over the next four years to recover profitability in R&M, and we have targeted to recover more or less €400 million of additional margin over the next four years. What are the main most important actions which support this recovery? As we have already stated, we refer entirely to organic moves, internal moves, in particular leveraging on integration between our refinery plants, improving the logistics between the various plants that we have, in particular in southern Italy, on savings in terms of energy costs. A lot of initiatives are already ongoing, and we expect to arrive to the end within the end of the year. A significant portion of these savings we expect to be able to achieve, some of them already by the end of the year.
Predominantly, our internal moves and leveraging also on the technical know-how that, in particular, our people of the refinery and marketing have, and we are deploying this know-how in order to improve the efficiency of our refinery plant. Organic moves, cost savings, efficiency, and flexibility. These are the drivers on which we will refer in order to obtain the €400 million recovery in margin.
Can you hear me?
Yes.
Hi. It's Jon Rigby from UBS. Three questions, please. The first is just to wrap up on the discussion we've just been having on the downstream. Obviously, with the new government in place in Italy and some of the ambitions that they have for changes to the Italian economy, could you talk about whether that is help with some of these ongoing structural problems you've had with the downstream and the inability to restructure and whether that's something that we should take on board? The second is just to go back on SNAM. I've seen stories in the past, and you never know what to believe and what not to believe, but discussion about whether there be staged sales, part sale, do you hold on to something, sell again a little bit later on, part for cash, part for shares.
Can you talk about whether there's options in between spin-off and cash sale and what your thoughts are around that? Lastly, just on Mozambique, can you confirm that it is your intention and/or your expectation that you'll become operator of the unitized area of one and four, if indeed that's the way it goes forward? Thanks.
On downstream and on the hopes that the Italian environment becomes Texas, I doubt, frankly. Frankly, I doubt it. I'm probably more used to Texas than to Italy, but this country remains a country, particularly in the south of the country, where employment is an issue, which does not mean that we cannot do things, but we should be doing things in a very wise manner. We are perceived to be too big and too rich to, let's say, not to create problems where we cut down employment and we do not offer alternative solutions. Now, all our plan, now I'm talking about chemicals, but we could do the same thing on refining.
All our plan is targeting shutting down production, losing money production, and increasing production, probably not on an equal footing in terms of employment, in new production which are more profitable, in which we use our technology, abandoned old commodity products. In R&M, in R, forget about M. M is doing well. Now, better or worse, we are always very positive. Of course, when the price of gasoline in Italy is above €2, you can imagine that the Italian drivers drive a lot less, which saves down, and therefore, even marketing is suffering. Generally speaking, I believe in marketing, we are making more money than our competitors. The problem is around refining. In refining, yes, we have a variable for which I'm very pessimistic in the long term, which is the refining margins in the Mediterranean.
I frankly don't see any reason why they should go back to $8, $9, $10, which we have seen three years ago, not 20 years ago. That is an area which I'm not expecting any good news. The area of the differential between light crude and heavy crude, which has been the, how can I say, the key around which any refining system has been built for 40 years, I mean, frankly, there is no reason why this gap should not go back where it has been forever. Let's say the differential between light crude and heavy crude today is what, Angelo?
$3.
$3. It has been forever $10. When the oil price was $60, $50 was 10. Now, at $120, it's 3. If you imagine our results, our results with a differential similar to what has been, you will see that our results are much, much better. Let me add another point. Every time that the cost of energy goes up, and for us, the cost of energy is the price of oil goes up, what happens is that we have in our reported result a loss. In our net result, we have a profit because while the price of energy goes up and therefore the cost of producing gasoline goes up, the stock that we have creates a lot of value. Of course, you do not see this value because we are not here liquidating the company.
In fact, if we take into account the growth in value of our stocks of today, this more than offsets all the losses we have made in retirement. I'm not saying this just to make us happy because we are not happy, but just to give you how important these two elements are in our account. As for actions in terms of refining, that is a potential temporary or permanent closure of some refining capacity in Italy, we do not exclude them at all. I don't know if I've been answering to your question, Claudio. Mozambique.
Mozambique. First, I'd like to remember that before talking about operatorship, we have to unitize the area. Once we have unitized the area based on the gas in place, we have to agree on a plan of development, and the plan of development must be approved by the authorities. I'd like to give you additional elements. First, we have a stake of 70% in area four. Second, we are the first operator in Africa. Third, we participate and we constructed eight trains of LNG in Africa already. We start from this position.
Okay. It's a good starting point, I have to say. Let me, on SNAM, a few words about SNAM. Now, of course, you are mentioning about potential combination between stock, dividends, spin-off, shares. Of course, there are all possibilities. Frankly, we are not there yet. We are not there yet. Of course, there are many ways to recognize the full value of SNAM shares in Eni. My view is simple. The day after that we lose control of the company, we want to get out. We are not in the business of holding 5%, 10%. This is not part of our business. I would add a second point. We would like to go out quick because we do not want to create a stock overhang on SNAM. We feel responsible for the well-being of SNAM shareholders. We have been bringing the company into the market.
We have been increasing the capital of the company a couple of years ago through the addition of Italgas and of Stogit. Therefore, we cannot forget SNAM shareholders, which remain for us a worry that we do not want to have. Yes, there are several possibilities. No doubt about that.
Great. Perhaps we could go to the call for a question from that and then return to the floor.
There's a question from Mr. Andrea Scauri from Mediobanca Milano. Mr. Scauri, please.
Mr. Scauri?
Yes, hello. Can you hear me?
Yes, we can.
Yes. Good afternoon, everyone. I have a couple of questions. The first one is on Mozambique. I was wondering if you see, if you perceive risk of an increase in the taxation in Mozambique. The second one is on the dividend. During the latest call, Mr. Scaroni clearly stated that an extraordinary dividend has to be excluded in the case of a cash deal on SNAM. I was wondering if a cash deal would materialize. Is it possible to foresee a more generous dividend on 2012 dividend base? Thank you.
Mozambique. I just remembered that we signed a contract, a PSA contract that starts from the exploration phase. Also, that is valid for the development phase. We don't foresee any change in the fiscality, and we don't have any bad signal on this sense at the moment.
Now, on dividend, you might remember that we stated a policy of dividend which was based on some parameters. It's probably not worth it for me to go back because I think it is well known by everybody. Now, this year, 2012, now forget for a second SNAM and potentially GALP, but it is true that oil price, even at our scenario of $90, is higher than the oil price of $70 on which our euro plus inflation was defined. That's true. We have to add on the other side that our Libyan production is not yet where it was when this policy was stated. This is somewhat an exceptional item. Let's say our view would be that everything being equal, the dividend policy of €1.04 per share seemed to us fairly correct and in line with our past and in line also with what our peer group is doing.
Now, when we move into what happens if we have a huge cash inflow from these potential sales of our non-core listed assets. I think I made quite clear the fact that if our company, as it is heading to, continues to accelerate its growth and is even targeting 2.4 million BOE by 2021. I mean, this will be the result of exploration, successful exploration, but also huge development plans which will require a strong balance sheet. Any change, potential change in our dividend policy after 2012, so 2013 onwards, will have as a North Star our strategy in order to continue to grow our production following our successful exploration.
Perhaps we can go back to the call, to the floor. Yeah.
Afternoon. Theepan from Nomura International. Just a couple of questions, actually. When you look at your E&P portfolio and the company as it stands today, increasingly, you are transforming yourself into a global E&P business that is very competitive. I look at the portfolio and it still seems, in terms of North America and the U.S., there seems to be an absence there. I was wanting to know whether you had any thoughts on whether you needed to add a position in North America. Claudio, I was just wondering on exploration as well, whether you thought you had, in the current portfolio, the ability to deliver your targets or, again, do you need to add incremental acreage? Clearly, you've had significant recent success in exploration. I was wanting to know whether there were any sort of internal changes that you've implemented that are creating these outstanding results.
For North America, first, we have a position in North America. We are producing about 120,000 barrels per day. We operate 65% of our production. We have a strong exploration campaign in the future in the Gulf of Mexico. We are going to drill in the next three years about 18 wells. We have an investment of €450 million in the four-year plan. I think that we can say that we have a strong engagement in the U.S. We have also a small participation in the gas shale. It's true that we'd like to increase our position there, especially in the oil shale, and we are thinking about that. Always through organic growth, starting from exploration assets. That is one of the points that we are elaborating.
The second question about the future, if you are able to continue to produce the same kind of result in terms of volume and quality, I think so in the next four years for the asset we have in Indonesia and the Barents Sea. I remember that in the Barents Sea, we have seven new prospects that we are going to drill in the next three years. We have to drill eight wells. We have more or less €300 million of investment, a little bit less. We have still a lot of potential. As I said during the presentation, I think that our geological model is very strong and well assessed. Norway is one very strong point with additional potential. In Angola, we're going to drill additional eight wells in the south part of Block 15/06 where we think that we can increase drastically the resources in this area.
Indonesia is another big hub where we acquire blocks. We acquire blocks. We're going to acquire additional blocks, and we have at least five or six prospects to be drilled in the next couple of years. Australia, again, where we have three blocks and we start exploration, we drill the first two wells these years. I think that we can confirm our success and our efficiency and effectiveness in the next four years. We changed something. Yes, we changed something some years ago. We tried to be more selective on the high-risk and high-reward assets. We tried to be more focused on the area where we had a very strong knowledge of the geological model. We increased the share and investment in the near field. We create a more near-field investment in exploration to assure a background positive result.
We have been more selective, reducing the big target, the high-risk target. That has been the change that we made. We also changed some part of our organization. We gave more focus on the exploration unit abroad and additional control on the geological model centralized. We changed something. That is true.
Very good. More questions?
It's Mark Blindfield from Deutsche Bank. A couple of questions, please. Just following on exploration. Just wondered how much of your 32 billion barrel resource base is attributable to risk exploration. If that, maybe you could give us a rough indication of how much is represented by Mozambique. Second point, coming on to gas and power profitability. I think sitting here a year ago, you talked about a $4.2 billion adjusted EBITDA target for 2014. I appreciate there's a lot of uncertainty going forwards, but reflecting SNAM, reflecting your recent contract renegotiations, perhaps you could give us some indication of where you expect normalized EBITDA to be in 2015. Thanks.
I start first with talking about resources. When we talk about 32.1 billion of resources, we have inside 7.1 billion P1. We have 6.5 P2 and 3.5 P3 and additional 6.1 contingent resources. We are talking about resources that we have already discovered. We have already discovered, we have already tested well and feasibility study until the P3 and contingent. We have, at the end, additional 8.9 or 9 billion of additional real resources. I mean, that there is a risk to exploration. That is the situation. Mozambique inside this is 5.4 billion barrel. That is the complete answer.
I'm working hard trying to give you an answer to your question about gas and power. Yes, you are right. We used to give $4.2 billion, of which the SNAM part was roughly $2 billion. Okay? In fact, this $4.2 billion was roughly $2 billion excluding SNAM. Okay? Now, today, as you said, to give a guidance in gas is one of the most difficult things you can do. This guidance has become extremely difficult because the market has become very volatile and extremely difficult. If we were to give a number, but a number which, please, consider that numbers today in the gas market are much less solid than the numbers we have been giving in the past, we would consider 2015 something around 20% to 25% lower than the $2 billion we gave in normal market conditions. Do I make myself clear on that? Yeah.
Sorry. Can I ask a follow-up to that question, please? I mean, in gas marketing specifically, I just wondered how much of the benefit of the contract renegotiations with Gazprom and Sonatrach you expect to hold on to and how much of that you think will be passed on to your customers to try and win market share, specifically referring back to your business-to-business growth targets?
To answer this question of yours is even more difficult. No, I explain to you why, because first of all, I cannot give you a precise number of contracts. This would be bridging all confidential agreements we have. Apart from that, these three contracts that we have been renegotiating in the last couple of years, with Libyan NOC, with Sonatrach, and with Gazprom, have three things in common. First of all, price has been lowered. When I mean price, I mean P0. Okay? We get back to this P0. Second, we have been reducing the take or pay mechanism. The take or pay, instead of clicking in at 80, clicks in at 60. We have some advantage in the sense that the volumes can go down without hitting us through the take or pay mechanism. Thirdly, which in my view is the most important of all, we can renegotiate.
Instead of having every three years of renegotiation, which was typical of this long-term contract. Remember, this long-term contract comes from a very long past. It has been the basis of this business for the last 50 years. We can renegotiate. Renegotiate, for me, is the most important thing, both sides, because this market is extremely volatile. Now, let me go back to the P0 and answer you why this question of yours is very impossible, is very difficult to answer. P0 means the price at which you start linking the number to the oil price. Okay? Suppose that tomorrow the oil price goes to $50, make an example, our price for gas will go down dramatically, and the price we pay to our suppliers, I mean, will go down dramatically. Our long-term oil-linked gas price will be super competitive to any stock price. Okay?
Suppose on the opposite, the oil price goes to $200. Our P0 is lower than it used to be, but at $200, we go very much up. It will compete with spot gas and will be extremely expensive. It is hard to answer your question because we don't know exactly where oil price goes. Of course, when I look at that from Eni, I have a kind of natural hedge in the sense that it's true. If the oil price goes to $200, this is bad news for my friend Umberto, but my friend Claudio would be very happy. No. And the opposite.
He's a good friend.
You see what I mean. That's the reason why it's very difficult to answer your question. I could answer your question if you tell me, please give me your answer at oil price of $80. I can give you an answer. I'm not sure I want to give you an answer, but I have a number in my head and I can tell you if our gas will be competitive or not at that time. Do I make myself clear?
Hi there. It's Jason Kenny from Santander. I recall in the past that you had an agreement with Gazprom whereby on your entry into Russia and then investing in Russia, you may actually then be able to sell Gazprom part of your international portfolio in return for investing in Russia. I just wondered if that was still the case. If so, if Gazprom has prioritized particular positions in your portfolio that they'd like to join you in. Secondly, a small clarification as to whether you're interested in Angolan refining, which I think has been mooted in the press.
Let me resume this old story about our so-called non-Russian transactions. When we bought the stake into what we call Sever Energy here today, that is, at that time, we called it SINT. That is our assets in the Yamal Peninsula, the one that Claudio has been describing to you in process. We will start production very soon, etc. We paid the whole thing, which, if I'm not wrong, our equity was 1.5 billion BOE made up of condensate and gas for a total of $1 billion.
$1.2 billion.
$1.2 billion. We bought for $1.2 billion, 1.5 billion barrels in the Yamal Peninsula, discovered but to be developed. As part of the agreement, we agreed that we would have let Gazprom buy half of the value, that is $600 million, in assets upstream and downstream outside of Russia. This was the agreement. This was signed in 2006 or 2007. Since then, we have been offering to Gazprom several alternatives. So far, we didn't reach any conclusion. The reason is the complexity of our business because in practically all our upstream activities, we need not only the agreement of the host country, of the oil country, otherwise we simply cannot do it, but normally everyone has a preemption right. As soon as we say, "But if we want to sell it, would our partners buy?" they say, "Yes, yes, yes." We have to pull back.
In downstream, it's somewhat the same thing. In some refineries of ours, we have partners. Let's say so far, we have not reached any conclusion. Just to answer your question precisely, yes, we have an agreement. Yes, we want to fulfill it. It is a very small thing because you understand, $600 million of assets is a minute portion of our portfolio, either in upstream or in downstream. Angola.
For refinery in Angola, we signed two years ago a framework agreement, a larger framework agreement with Sonangol concerning gas upstream assets, oil upstream assets. Inside this agreement, there is also the refinery in terms of studies and feasibility studies. That's what we are doing and that's what has been reported in the newspaper. There is not yet a project sanctioned. There is just a discussion and a feasibility study ongoing.
It's Neil Morton at Badenberg. I had an upstream question on Kazakhstan. I'm looking at the slide. Can you just confirm that the 2021 production guidance does not include a third phase of Karachaganak or a second phase of Kashagan? Then just secondly, on Kashagan phase two, what is your attitude towards that amid rumors that some of the other IOCs are looking to head for the exit? Thank you.
On the long-term production 2021, there is not a second phase. There is a risk portion of the third phase of Karachaganak also because now we finalize all our agreement with the Republic. We are starting the third phase, and the Republic is willing to go ahead with the third phase. We think that in maybe less of a couple of years, we'll be able to sanction the project. We are quite confident about the contribution in the long term. For the second question, I cannot answer anything about rumors. I don't know anything about rumors. We are finalizing the negotiation of the amendment four, and immediately after, we're going to start discussing about the phase two. Talking about Eni, we are 100% focused on the first production.
One more question here.
Thank you. It's Colin Smith from VTB Capital. I've got two questions. The first one was just if you could tell us where things stand on South Stream now because you didn't mention that in the presentation. The second question was you identified the right to renegotiate as being the most important component of the agreements that you've reached with the three pipeline suppliers that you've reached agreement with. Given that you had the three-year price reopener clauses, I think with them anyway, could you just elaborate a little bit on what the right to renegotiate means that's different from what you had before? Thank you.
Let me answer first to the second question, which is very easy. We asked and agreed what we call a joker in the agreement. That is, the agreement continues to be the same, the same old agreement. Every three years, the parties get together and negotiate prices. We have a joker that we can play anytime if we want to renegotiate within the three-year period. For example, take the example of the last deal we signed with Gazprom. We could, beginning of 2013, that is one year from now, start a new renegotiation phase if prices are very different from prices or whatever price we have in Europe. We have an opportunity.
I have to tell you frankly that I could have any kind of agreement on price and on the take or pay, but without the joker, I would not have signed because the level of uncertainty is so high that it becomes a threat for everybody, for us as the seller and for them as a supplier. I think it is fair to recognize that this market is totally different from what we have seen for many years. I've been in Houston last week to speak about gas and all these kinds of things. Every time I think that the same molecule of gas is worth $2.2 per million BTU in the U.S., $10 in Europe, and maybe $11 or $12 for long-term oil-linked contracts, and $16 or $17 in Japan, the same thing. This scenario is so awkward and strange that nobody really knows what will happen.
I am sure that will not last forever, this differential. I could add at $2.22, a calorie coming from gas in the U.S. costs one-eighth of a calorie coming from oil. One-eighth. For how long this absurd differential will last? Therefore, we have added this clause which allows us to renegotiate. Now, on South Stream, South Stream, in simple terms, why we are in favor of South Stream? We are in favor of South Stream essentially for three reasons. The first reason is being a major player in the European gas market, we need to ensure to our customer reliability and security of supply. We have seen too many times that problems raising from transit countries jeopardize the security of supply of our customers. I prefer to have a pipeline which crosses the Black Sea rather than a pipeline that crosses a transit country. Essentially, this is the first reason.
The second reason is that the whole mechanism, which is at the origin of these pipelines, makes it normally an investment which is fairly easy to finance through non-recourse financing from banks because it is guaranteed by a ship or pay from the supplier and a take or pay by the customer. Therefore, the amount of equity involved normally is limited. Third, I cannot forget that Saipem is the candidate to build this pipeline. It has built Blue Stream, which is crossing the same Black Sea. It has, I believe, probably the only one ship ready to make the erection, the laying down of the pipes. Therefore, we have an additional interest. It is a very reliable supplier to Gazprom because it has built a North Stream, as you may remember. In total, I see several interests for us to follow this project.
We are not at the end, but we are confident about the future of this project.
It seems that there are no more questions from the floor. That's correct. Operator, could you confirm that there are no more questions from the call?
No more questions from the call.
Great, thank you. That's the end. Let's Start your presentation.
Ladies and gentlemen, the conference call is over. Thank you for calling Eni. Press one to play a recorded conference. Press nine to exit.