Good afternoon, ladies and gentlemen, and welcome to Eni's exploration and production update conference call in connection with the field trip in the Republic of Congo, hosted by Paolo Scaroni, Chief Executive Officer, Claudio Descalzi, Chief Operations Officer, Alessandro Bernini, Chief Financial Officer, and Roberto Casula, Executive Vice President Sub-Saharan Africa. 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 your host to begin today's conference. Thank you.
Good afternoon, ladies and gentlemen, and welcome to our field trip to the Republic of Congo. I hope you found the meeting with the questions of the Republic of Congo interesting and fruitful. I'm also pleased that you had a chance to witness the excellent relationship that we have with the local institutions here. This is a trait that characterizes our approach wherever we operate, especially in Africa. Today, I will tell you more about the distinctive ways in which we try to build and consolidate relationships with our host countries and how they support our growth prospects. The program for the next couple of hours: after my brief overview, I will hand you over to Claudio Descalzi and Roberto Casula, who will take you through our major E&P projects around the world and in the region.
Then to Alessandro Bernini, who will bring you up to date on our financial position. First, let me give you an update on a few issues which you might be interested in. The first is Libya. In Libya, we are working closely with the new management of NOC to restart all our operations. In the last few weeks, we have been to Benghazi and Tripoli. We opened our offices in Tripoli and restarted production at our Istiklal oil field, which is producing almost 70,000 barrels a day. As for our other oil fields in Libya, including Elephant, wells, facilities, and transportation systems have not been damaged. In general, we expect oil production to reach pre-crisis levels in about 12 months.
With regards to our gas field, which accounts for around 70% of our median production, our employees have boarded the Sabratha platform at the Bahr Essalam field, located in the sea off the coast of Tripoli. If security allows, we will restart production from this field before the end of the year. All gas production will be restored in the early part of next year. Meanwhile, we resume gas exports to Italy through the Greenstream pipeline, gradually starting this month. As well as the E&P production, Libya has also impacted gas and power results, and we are doubtfully pleased we are heading towards a resolution on this front. Another major uncertainty affecting gas and power in 2011 has been the ongoing renegotiations of our main gas supply contracts with Gazprom and Sonatrach.
Trying to give an update on this front, our discussions with Sonatrach have been positive, and we are close to reaching a mutually satisfactory conclusion. Our discussions with Gazprom are progressing, and we have seen evidence of an increasingly constructive dialogue. While it is difficult to be deterministic about the timing of a deal, we remain confident about the outcome. The satisfactory closure of these negotiations will improve our supply costs, making them competitive with spot prices. It is true that spot prices have risen over the past few months, thanks to increasing gas demand in the Far East, offsetting weaker gas demand in Europe. Our oil link prices have also been driven upwards by higher oil prices, keeping the gap open.
Finalizing the ongoing renegotiation with our suppliers will remove a significant uncertainty in our gas and power business and put us in a good position to grow volumes and profits when the gas market tightens, which we expect by 2013-2014. Now let's turn to another topic you might be interested in: our main subsidiaries. With regards to SNAM, as you know, our strategy has changed since the adoption of the European Third Gas Directive, and we have been studying options to unlock value from this stage. We will provide further information on this topic at our next strategy presentation, bearing in mind that any disclosure will need the approval of the Italian government. Our aim here is to make the whole process shareholder-friendly for investors in both SNAM and Eni. Turning now to SIPEN, nothing has changed.
SIPEN is a core part of our strategy and has material synergy with our upstream. Last but not least, GALP. As we have said before, we are working to crystallize the value of our stake. There is no doubt that there are parties which are interested in acquiring it. Meanwhile, our shareholder agreement means that any disclosure will need to be agreed with our partners, Amorim Energia, and the Portuguese government. Now let's get back to the reason why we are here. Africa is our core area. We have been present on the continent since entering Egypt in 1954, and in normal times, we produce here 1 million BOE per day, or around 55% of our total production.
This production level was achieved through significant growth of around 6.5% a year over the last 40 years, in which we increased our share of African production and consolidated relationships with many important producing countries. Today, we count on relationships spanning several decades in North Africa and in Angola, Nigeria, and of course, Republic of Congo, and have built an unparalleled presence in the new oil-producing countries in the continent. As a result of our long history of growth, today we are the leading international oil company in Africa. We are the leading IOC in terms of production, having more than doubled African output in the past 15 years. Our current production in Africa is around 35% higher than that of our closest competitors. We are the leading IOC in terms of geographical footprint, with production operations in seven countries and exploration and development projects in many more.
Being the first IOC in Africa has a number of advantages in terms of scale, synergies, and access to projects within no break-even. Our leadership is set to continue for the next decade. That's because of the significant growth opportunities we have on the continent. Our growth will come from major startups in our legacy countries and from high potential exploration prospects in the new countries we have entered: Ghana, Togo, Mozambique, Gabon, and the Democratic Republic of the Congo. Africa also has a key role in the development of our unconventional portfolio, with initiatives in Nigeria and Tunisia and in South Africa. Meanwhile, we are working on the tar sands here in Republic of Congo. You may be wondering why we had such a success in Africa over the last 40 years.
One may think that we are advantaged by being Italian with a smaller colonial past on the continent. We think the real competitive advantage we have here is our approach to doing business. Our Eni model, built over the last half a century, gave us a unique edge in securing access to resources. Our model is made up of a number of differentiating factors, of which the first is our core E&P expertise and technology. As well as this, Eni has a number of distinctive benefits it can offer based on our competence along the role of the oil and gas value chain, coupled with our commitment to local, social, and economic development. Not all the legs of our model are applied in all of the countries in which we operate, and in every country, some are more important than others.
We'll now take you through some key examples of our model and its advantages. Looking at North Africa, a major differentiator in our dialogue with producing countries is our upstream/midstream integration. Among the majors, we are the only one with a leading position in the European gas market, which we supply by buying around 80 billion cubic meters of gas. Being a big buyer of gas has been key in developing stream opportunities in Algeria, Egypt, and of course, Libya. Our integration along the oil and gas value chain is the base of our strong relationship with North Africa, which makes up more than a quarter of our gas supply portfolio and a third of our E&P global production. Moving now to Sub-Saharan Africa, other aspects of our model become significant in accordance with the needs of the local population.
One of the region's most pressing issues is the lack of electricity. 600 million people, almost two-thirds of the African population, including many here in Congo, have no access to any electricity at all. At the same time, Eni is fully committed in eliminating gas flaring. Eni tackles both these issues, having been the first IOC to invest in power generation in Africa using gas previously flared. We implemented major electricity generation projects in Nigeria and in Congo, and now we account for 20% of Nigeria power generation and 60% of Congo's. The success of our approach has caught the eye of other countries in the region and has supported Eni business development in Angola, Ghana, Togo, and Mozambique, where recent MOUs include potential PowerGen projects. A third distinctive trait of our model is our double-flag approach.
We are an international company, but in every country, we are a local operator. This means a number of different things. For one, it translates into a greater willingness to take on offshore projects. Being a local company means also investing in local people. Over the last 10 years, we have not just grown the overall number of locals employed in our operation in Sub-Saharan Africa, but also invested in their training and development. Today, the proportion of local staff in managerial roles has almost doubled, and we are committed to growing further. It's particularly appropriate that we should talk about the Eni approach here in Congo because Congo is one of the fuller examples of the model, and I hope you will enjoy your site visit tomorrow. I will now hand you over to Claudio for an update on our main E&P project.
Thank you, Paolo. Good afternoon, ladies and gentlemen. I'm pleased to welcome you here in our office in Brazzaville and take this opportunity to give you a broad update on our strategy and project. One of the main aims of my presentation today will be to elaborate on the strength of our growth prospects, not just for the next four years, but also for the next decade. To give you some additional granularity on the future development opportunity of our exploration, in our view, a sustainable value creation has to be underpinned by an efficient growth process coupled with strict risk management. We will deliver growth through the rapid and efficient development of our existing projects and resources, and through an exploration strategy focused not just on finding resources, but on finding the resources that can be developed quickly and providing attractive returns.
For us, risk management starts from the quality and mix of resource base. From the beginning, our strategy has been oriented on conventional assets onshore and in conventional water, which are technically less demanding and more efficient to develop. Secondly, to reduce risk and be more efficient, we have focused our presence in core areas, which means areas where we know and understand from a geological standpoint, where we have technical and operational synergies, and where we have consolidated the relationship with local institutions. Building on these two strategic drivers, additionally, we control and minimize operational risk investing in new technology, on people core competencies, and by increasing operatorship. This approach enables us to target significant growth, not just to 2014, but also for the next decade.
We confirm the target of production growth of over 3% a year on average to 2014 at EUR 70 per barrel, or 2% at EUR 100 per barrel. We are also setting an average growth goal of around 2% a year between 2014 and 2021. This is based on further development phases of giant projects, new identified projects from exploration success over the last few years, and offsite potential from promising exploration. Let's look at the projects which will provide growth in 2014 in more detail. In the next four years, we plan over 40 startups. New production will be geographically diversified with major contributions from Africa, which accounts for over 40% of new production, OECD countries, which will provide around a quarter, Russia and Central Asia, and Venezuela. 60% of new production by 2014 will be oil, and 85% will be from sealed onshore or in conventional water.
Many of the major startups will come through in 2012 and 2013. These include Block 15/06 in Angola, Perla and Equion 5 in Venezuela, the giant field in Russia, and Kashagan. So far this year, we have made big progress on all big cornerstone projects, which will provide over 200,000 barrels per day of production by 2014. In particular, we have recently taken the final investment decision for Samburskoye and are on track on Sanchu Urengoyskoye, Perla, and the second half of Block 15/06 in Ossi Povo before the end of this year. Looking beyond 2014, the outstanding exploration results achieved in recent years will drive further growth. In the two years, 2009 and 2010, we discovered around 2 billion barrels of new resources with an extremely competitive unit exploration cost of EUR 1.6 per barrel.
This was remembering the huge success in Block 15/06 with more than 700 million barrels of reserves discovered, with a success rate of nearly 90%. The Perla supergiant, with almost 12 TCF of reserves, and Cuelone and Greater Adrian area. In 2011, we added so far about 480 million barrels of resources by drilling 38 wells, of which 29 have been successful. Sorry, 29 have been successful, and confirming so far the very low unit exploration cost recorded in the last two years. Among these, we are particularly excited by the Skrugard discovery in the Barents Sea, with the last estimate confirming about 250 million barrels of recoverable reserves. Jangkrik and Jangkrik Northeast discovery in Indonesia, where we discovered approximately 4 TCF of gas in place.
In Ghana, the recent Gye Nyame gas discovery confirmed the potential of the area and opened up the possibility of synergic development with Sankofa, discovered in 2009 and successfully appraised in 2011. In Angola, with the recent gas and condensate discovery of the Cabaça in the southern sector of Block 15/06, the well has been successfully tested, showing excellent productivity. We are working quickly to convert these new resources into production through projects that will be sanctioned in 2013 and 2014. On top of this, we have further phases of development of existing giants, among which Tunu, Perla, Djeno, the Rajangas field, Karachaganak, Kashagan, as well as a further hub in the Block 15/06. As Paolo Scaroni mentioned earlier, in Libya, we have a large discovery, but yet still undeveloped resources, from which all feasibility studies have long been finalized.
The development of these additional projects would roughly double current offshore gas production, further supporting long-term growth. Growth opportunity beyond 2014 will provide about 1.2 million barrels of oil of new production per day, of which 85% from giants in long plateau periods. The growth projects in the middle-long term are focused on six key regions or hubs, which will provide about 45% of our production by 2013 and more than 50% by 2021. Now, some details for each of these hubs. Starting with Russia, our presence in the Yamal Peninsula has huge potential. Our four licenses in five blocks contain overall 1.5 billion barrels of APTP reserves, and we plan to reach a production plateau in 2019 of 200,000 barrels per day for a period of roughly 10 years. We have recently finalized a commercial agreement with Gazprom for the sale of gas and with Novatek for condensate.
Sambuskoye will be the first field to be developed. We have already taken SID, and we confirmed the startup in 2012. Gas per barrel is estimated at around EUR 4. The second field to go into production will be Yaroyanchish field. A pilot development plan was submitted to the authorities last year, and production startup is foreseen in 2012 as well. A third startup will be the Urengoskin field. We plan to sanction the project in late 2011, and startup will be in 2014. Two further giant fields, Severo and Ievo, will start up by 2018. Another driver of long-term growth will be the Barents Sea, an important oil hub with great potential in the OECD. The existing oil project, which will provide around 55,000 barrels per day of production by 2013, is on track.
Overall progress is at 22%, with the first offshore campaign completed and all the A subsea templates already installed. The FPSO is currently being built in Korea, and we expect it to be delivered in summer 2013. We confirmed the startup in late 2013. On top of that, we plan to fast-track the development of the recent Struga discovery, where we are aiming for a startup in 2016-2017. The two projects combined will provide a plateau of 70,000 to 80,000 barrels per day APP oil production, bringing Norway contribution to almost 200,000 barrels per day. The Barents Sea also has exciting growth prospects. We have an additional 11 exploration blocks, which we are going to start drilling from the next year. Let's now turn to Indonesia, where we have made significant gas discoveries, which will benefit from the existing infrastructure, including the Bontang Energy Plant and strong gas market.
Overall, our conventional and unconventional assets in the area will provide around 100,000 barrels per day APP production active. The first project in the area is the CBN field located beneath our conventional Sanga-Sanga field, where we estimate resources of almost 13 TCF. Today, three dewatering wells have been completed, and in March 2011, the NDP joint venture became the first consortium in the world to deliver CBN production to an energy plant. We expect production to start up in 2013, and the gross production will exceed 70,000 barrels per day around 2020. Meanwhile, Jangkrik discovery is even more significant than it seemed at first. We have successfully completed the drilling and testing of Jangkrik Northeast 1 and 2, finding new gas accumulation for total resources, which have almost doubled from 2 to 4 TCF. Turning to Venezuela, and this will be a key growth area.
The two giants, Junin 5 and Perla, will contribute 45,000 barrels per day of production by 2014 and 170,000 barrels per day by 2019, a plateau which will last for the following 20 years. In the first half of the year, we agreed all the details of the Junin 5 development plan with PDVSA, including the possibility of building a power production startup in 2012, with initial gross production of 10,000 barrels per day. We tested the reservoir and for the facilities to be ready for the first phase of production startup, which we confirmed for late 2013. Drilling will begin by the end of 2011. The first phase of production will peak at 75,000 barrels per day. A full field development requires the drilling of more than 1,400 wells and the construction of an upgrader.
Regarding the Perla, at the beginning of 2011, we completed the field for both onshore and offshore. The EPC contract will be awarded by December 2011. The field will be developed at an extremely competitive cost of EUR 3.5 per barrel. We are finalizing the commercial agreement, and we expect to sign the GSA and pay the SID before year end. Kazakhstan is another major hub for Eni. Between Karachaganak and Kashagan, we have over 1.1 billion barrels of APP. Project. We have a session with Kazakhstan on quality compensation. Finally, I will touch upon Sub-Saharan Africa, which is an extremely important hub, and which Roberto Casula will take you through in more depth.
A main driver of production growth in the area will be deep water development, with peak production of around 180,000 barrels per day, and LNG and power generation projects, which will enable us to monetize associated and non-associated gas. Sub-Saharan Africa is one of the three key themes in exploration, with onshore and offshore crystal plates, the already prolific Tano margin in Ghana, and the tertiary plates in Eastern Africa. Overall CAPEX in the region will be around EUR 1.3 billion for the next four years. The second theme is Arctic, and particularly the Barents Sea, where we will drill in 2011-2014 nine new wells for an investment of EUR 230 million CAPEX investment. The third theme is gas in the Pacific Basin, where we have recently added three high potential blocks, two in Indonesia and the other in Australia.
Eni's effort to increase its exposure to this region will be fueled by CAPEX of EUR 650 million. Consistently with the exploration strategy, all these three themes have clearly identified development options and benefit from synergies with existing operations. Our growth over the next decade will also be supported by increasing the exposure to unconventional gas. Building on the competencies and experience acquired in the joint venture with Quicksilver in the Barnett Shale, we have built up a portfolio of promising prospects outside the U.S. In particular, we are focusing on areas where there are synergies with existing operations, where infrastructure is already in place, and where the gas market is strong or is growing. A good example is North Africa, where we are the leading producer and where domestic demand is growing exponentially.
Here we have expanded our presence by signing the cooperation agreement with Sonatrach in Algeria for shale gas, and we are continuing to explore opportunities in Tunisia. Meanwhile, in Europe, where Eni is one of the largest players in gas, we are making good progress in Poland, where we will drill the first well by year end, and in Ukraine, where we have signed MOUs with the state-owned company to start its initiative in conventional and unconventional oil and gas. The Southeast is a key growth area for us in non-conventional as well as conventional gas. In addition to the CBN project in Indonesia and tight gas exploration in Pakistan, we have entered China with two MOUs, one with the CNPC State of China and the other with Sinopec, again access to the vast shale gas resources in the country.
Over the next four years, we want to invest at least €30 million for unconventional exploration and more than €500 million for development. Total unconventional resources amount to over 1 billion barrels. E&P portfolio is not just a captive in terms of growth prospects. We are one of the IOCs with the lowest costs consistently across the value chain, and over the next four years, we will continue to concentrate on efficiency. In exploration in the last few years, we have delivered one of the best unit costs of the industry, and this is something we plan to maintain through our outstanding portfolio. Meanwhile, the focus on unconventional assets and the exposure in our core areas enable us to develop the project at an average block ceiling price of only EUR 45 per barrel.
The cash flow per barrel of E&P division is one of the best in the industry, and our project pipeline will enable us to grow it even further at a flat EUR 70 per barrel scenario, driven by the scale benefit of a giant project and increasing exposure to oil over the planned period. To sum up, Eni is entering into a period of accelerating growth, which will be sustainable for the next decade. So far this year, we have made good progress on all strategic goals, and especially in terms of exploration, we have discovered giant fields in some of the fastest growing areas in the world, with a substantial increase in resource base. Development on new discoveries in our major hubs will benefit from cost and time synergies with existing operations. Outstanding exploration results coupled with focus on fast time to market will sustain our long-term profitable growth.
I will now hand you over to Roberto for a closer look to our key one of our key pillar strategies.
Thank you, Claudio, and good afternoon, ladies and gentlemen. I'm here to give you an overview of our activities and prospects in the Sub-Saharan region. Before I do so, I wanted to give you a little context. Sub-Saharan Africa is a vast area populated by 850 million people, with a demographic growth of over 2% a year. As mentioned earlier, the economic development of the area is hampered by energy poverty. Power generation is among the lowest in the world, and the overall electrification rate is below 30%. Another issue is health. Later on, you will appreciate the merits of our initiatives in this context. Sub-Saharan Africa is rich in natural resources, both oil and gas and minerals. The hydrocarbon potential is considered very high due to the excellent prospectivity in deep water, in land basins, gas exploration, and unconventionals.
Eni's presence in the area goes back to the early 1960s, and our activities here have grown over time and will play a pivotal role in Eni's future. We target Sub-Saharan production growth of 6% per annum in the next four years and average growth of 2% per annum in the period 2014-2021. We will grow thanks to the continuing development of our activities in Angola, Nigeria, and Republic of Congo, and further exploration potential in existing and new countries. Specifically, the addition of countries such as Ghana and Mozambique with their gas potential will contribute significantly to long-term growth. Our production growth in Sub-Saharan Africa is based on four main drivers, so let's look at these more closely. The first one is the development and startup of a mostly operated deep water project.
The second is gas utilization, capitalizing on Eni's presence along the wall of the gas value chain to monetize stranded gas and maximize the value of non-associated gas. The third key driver of growth will be exploration. As Claudio was saying, Sub-Saharan Africa is one of Eni's main exploration fields, and we have exciting opportunities in the most promising basin. Lastly, our operation model, which combines oil and gas development with social projects and provides a competitive advantage in obtaining access to new resources. Let's start with the deep water project. Deep water has always been an area of excellence for Eni. We were the first company to start deep water production in Nigeria. Since then, our exploration success has resulted in a number of interesting projects, both producing and in development. Long-term perspectives are even brighter.
Eni is well positioned, as I said, within the most promising basin in the region, with total resources estimated at around 10 billion barrels of oil equivalent. Looking more closely at the next four years, we will raise production from deep water activity from 130,000 barrels per day in 2010 to 180,000 barrels per day in 2014. Most of the output will be oil, and 46% of this production will be operated by Eni in 2014, compared to 25% in 2010. Water production will be 36% of total Eni Sub-Saharan Africa in 2014, up from the current 32%. Two projects will play a key role in our deep water engagement: Block 15/06 in Angola and OPL 245. Let's take a look at each in turn. In Block 15/06, following a successful fast-track exploration campaign which ended 18 months earlier than contractually due, we are implementing two projects.
Firstly, the West Hub project, consisting of developing the Sangos, Woma, and Cinguvu fields, followed by the tie-in of all surrounding discoveries, which increases the potential of the hub up to more than 200 million barrels. FID was taken at the end of 2010, and the project will cost EUR 2.8 billion. The startup is set by 2013, with an expected peak production of 80,000 barrels per day. On top of the West Hub, we plan to sanction the East Hub project by the end of 2011. We intend to develop the discoveries of Cabaça North and South East for a total of 200 million barrels through an FPSO with a capacity of 120,000 barrels per day and the production startup expected by 2014. The full life cost in this case is forecast in the range of EUR 3.4 billion.
Both the East and West Hubs will have a time to market of around five years, from discoveries to production. In Nigeria, we were assigned a 50% participating interest and operatorship of one of the most important undeveloped deep water blocks, OPL 245. With almost 500 million barrels of already discovered reserves, our commitment is for a fast-track development to bring the fields of Zabazaba and Etan to production by 2015. The preliminary development scheme foresees an FPSO installation with 120,000 barrels per day of capacity, the drilling of 28 wells, and the laying of a gas export sea line to route the associated gas to Bonny LNG, which will result in additional revenues. Further to the discovered reserves, the block has additional exploration upside. We intend to appraise the already discovered fields and investigate the unexplored structures. Let's now turn to the second driver of our growth: gas utilization.
We, as Eni, have always considered that gas is an economic, industrial, and social opportunity, either coming from flaring down projects or development of non-associated gas. Currently, 14 main gas utilization projects are in the Eni portfolio, and we have planned investment in the range of EUR 5 billion for the next four years. These projects will total proved reserves of 1.3 billion barrels of oil equivalent and will contribute over 120,000 barrels per day of production by 2014. Particularly important are the flaring down initiatives. Gas flaring is widely perceived as a major issue, both for environmental and value-adding purposes. Eni has been highly proactive in promoting the flaring down. As an example, in Nigeria, we flare today only 10% of onshore associated gas, and by next year, it will be lowered to about 5%.
The same applies to Republic of Congo, where we target onshore zero gas flaring by 2012. Finally, Angola, where we are participating in a major offshore gas flaring down through multiple projects. A quick look now at our LNG business. First of all, why LNG? For producing countries, LNG projects are important for two main reasons. Firstly, increasing revenues through gas utilization, and secondly, creation of basic infrastructure to fuel domestic growth. For instance, the large LPG production capacity of the LNG plants greatly modernized the energy sources, which are largely based on wood and charcoal, thus reducing deforestation. For the IOC, the LNG allowed their presence in the integrated value chain from producing well to the final end user market, determining an efficient monetization of gas reserves from many fields.
Our presence in LNG in Sub-Saharan Africa dates back to 1989 with the participation in the Bonny LNG, which production commenced in 1999. Our presence expanded further by joining the Angola LNG project in 2007, where production started planned for February 2012. At the same time, progress has been made to reach FID for Brass LNG in Nigeria. Last but not least, through our participation in the Angola gas project, we shall secure supply for a second train of Angola LNG. Let's now turn to power generation, which is an excellent opportunity to support the economic and social development of host countries. Our first power project was OKPAI in Nigeria, a 480 megawatt plant, which was the first double-cycle plant in Africa. It was followed by a gas supply contract to the River State Government power plant.
Both plants are now fully operational, and the OKPAI plant has been acknowledged as the most reliable power plant in Nigeria, with a percentage of availability of 99.8%. In Congo, Eni started generating gas fuel power in 2002 with the 50 megawatt Central Electricity of Geno, and in March 2010, we started producing electricity from the 300 megawatt Central Electricity of Dugongo. In Angola, as part of the 2008 framework agreement signed with Sonangol, we are discussing the construction of a 450 megawatt gas power plant in the area of Bambi. In total, Eni in the Sub-Saharan region has installed a nominal capacity of 1 gigawatt, reaching over 18 million people. We intend to grow further in this sector as our capabilities and experience are valuable to new countries in which we are entering.
I will now start to explore which we expect to drive Sub-Saharan production growth in the longer term. Eni is active in three prolifically proven petroleum plays in Sub-Saharan Africa. The presalt play is aiming to replicate the Brazilian Santos Basin play. Our evaluation to date provides us with the confidence that significant volumes exist along the West African coast up to the deep water acreage, such as Block 35 in Angola. Moreover, we are among the few companies exploring these plays onshore. Secondly, the transform margin play, whose importance is testified by the success of Sankofa Gye Nyame campaigns in Ghana, and which extends the Jubilee trend. We plan to explore this trend even further into our Togo acreage.
Finally, the tertiary play is proven through our acreage in Nigeria and Angola 15/06, and this year, we shall investigate the potential of the significant hydrocarbon resources in deep water Mozambique Block 4. Looking at the play in more detail, the presalt play along West Africa is now more easily identified using new technology named imaging to understand the geology under the base of a thick salt layer shown here in red. Prospective areas are where sediments lie over basement high. In the recently assigned Block 35 in Angola, we plan to acquire in 2012 at least 2,500 square kilometers of 3D seismic, and then a drilling campaign will follow in 2013. The transport margin play relates to a basin formed during the separation of South America from Africa, lifting up a unique basin between elongated point zones.
In this basin, we have obtained over the last three years a good acreage position and already made two discoveries in Ghana, whose development is under further discussion with partners and Ghanaian authorities. Looking at the tertiary plays, we have been successful along the West Africa coast, more recently in Angola 15/06, Block 15/06. We are now assessing the similar plays along the East African coast, as I said, the Block 4 Mozambique. As you know, the industry has had significant success in this play with seven recent discoveries out of nine drilled wells, the largest of which is directly adjacent to the west boundary of our Block 4. We are drilling at the moment the first of these wells to be completed this year, and two more wells are planned next year. Clearly, a discovery will open a new front for us in East Africa.
In terms of development options, we are thinking about an LNG plant to export gas, especially to Far East, while part of the gas volumes would be made available for the domestic market. Our fourth growth driver is the Eni cooperation model, a distinctive approach which gives us a significant advantage in securing access to resources. As we heard earlier, all the activities we carry out and all the activities we are talking about today are part of our model of cooperation with host countries. Operating with responsibility while investing in the country's future represents the dual flag approach. One flag is the flag of the country, the other shows the six-legged dog.
This led to moving in a decisive way towards a partnership around a shared business plan, development of infrastructure, support to national content, excellency through education, genuine commitment to social responsibility, and an enlarged vision beyond national borders through international partnership. All this enables us to work on all available energy resources, making sustainable development a distinctive element for common value creation. As an example of this integrated approach and how it embraces our core activity, I want to give you a quick overview of what we are doing in Mbundi. When Eni acquired Mbundi back in 2007, the field was being developed as a traditional oil field, with all the gas burning in the atmosphere and with limited pressure maintenance through freshwater injection.
Since then, Eni has worked to transform the Mbundi field into the main energy hub of the country, and this has been achieved through a number of things: the development and connection of nearby satellite oil fields, the implementation of a seawater injection through the construction of a 55-kilometer pipeline from the coast, thus preserving the freshwater natural resources, the implementation of a large-scale gas development plan through a 16-inch gas line to the newly built power station in Geno and Kot Matel. The electricity is currently feeding the recently revamped national network. These projects have already allowed for a dramatic decrease of the flare gas, while the zero flaring targets will be reached by 2012 with the implementation of the gas reinjection project at Mbundi field. Future gas will come from the Marine 12 offshore project.
Further volumes are linked to the connection to the Koraf refinery and to the potash mining industries. Finally, future gas will also feed a new LPG plant to produce butane for domestic consumption and the Tarzani plant. All this is tightly linked to a comprehensive plan of intervention in the surrounding area, so as to build a constructive relationship with local communities who perceive our presence as an opportunity to improve their lives. A clear example of Eni's efforts to improve our relationship with the local communities is represented by the many social projects developed alongside our industrial operations. The main areas of intervention concern health, infrastructure construction and/or refurbishment, agriculture, support to education and capacity building, and ensure safe and constant water and electricity supply. For example, in Nigeria, we developed two agricultural projects impacting 500,000 people.
In the domain of health, our vaccination plans in Congo and Angola involved 500,000 women and children. Here in Congo, we have also launched an integrated project with Columbia University, spanning the sectors, as I said, of agriculture, health, education, etc., which has been instrumental in establishing a positive relationship with host communities and which you will better be able to appreciate tomorrow during the site visit. Eni's success in West Africa has been built over several decades, leveraging on our recognized leadership as an efficient operator. Our focus on conventional and large-sized projects allows us to benefit from significant economies of scale and operational synergies. Meanwhile, the deployment of our technologies, continuous operational improvements, and the production optimization effort allow us to contain operating costs, while our integrated model gives us the ability to monetize low-cost stranded gas resources.
As a consequence, we project solid cash flows from our African operations, which will benefit from significant leverage to oil price upside. Thank you for your attention, and I will now hand you over to Alessandro, who will give you an update on Eni's financing.
Thank you, Roberto, and good afternoon, ladies and gentlemen. All of the activities and projects illustrated this afternoon will contribute to the growth of our cash flows over the next years, which will be mainly driven by the increase in E&P production. Over the next four years, the cash flow generated by our operation will be more than sufficient to fund dividends and the capital expenditure program, which is focused on our high-value upstream project pipeline. E&P development activities account for the lion's share of Eni's CapEx. Our development projects are characterized by two trails. A large majority of them are conventional in nature. Three-quarters of development CapEx are related to onshore and shallow water fields, which have a lower risk profile and usually lower development and operating costs than deep water or unconventional activities.
Furthermore, almost half of our development CapEx are related to PSAs, which guarantee the recovery of investments made while still being leveraged to potential oil price upsides. As well as financing our higher return CapEx plan, our cash flow growth over the planned period will progressively strengthen our balance sheet. Maintaining a strong balance sheet is one of our key priorities as we want to be able to access the market even in difficult trading conditions, such as the ones the Eurozone is experiencing now. One of the strengths of our balance sheet is that our consolidated net debt of €26 billion is associated with the low-risk activities. Around approximately €11 billion belong entirely to SNAM, which has a stable and solid cash flow that covers its investment needs. A short €3.4 billion is attributable to Saipem, whose operations will positively contribute to the group's financial position in coming years.
Looking at the full year 2011, we have already completed disposal for almost €1.7 billion. Combined with the effect of higher oil prices, which offset the impact of the Libyan crisis on our results, this enables us to confirm year-end net debt-to-equity ratio below the 0.47 posted at the end of last year. Looking further ahead to the next four years, our target remains to achieve a debt-to-equity ratio below 40% without considering any major disposal. Should our disposal be finalized, the benefit of this transaction on our leverage could be in the range of 9 percentage points. In this time of market turbulence, we can rely on a financial debt which is well diversified by source of funding and is characterized by an optimal profile in terms of both composition and ratio.
Over 80% of our gross debt is mid-long term, with an average maturity of more than five years. In the last few days, we have successfully placed around €1.3 billion retail bond with a six-year maturity, which confirms Eni as one of the most rewarded issuers in the bond market and further expands the profile of our funding. Indeed, the proceeds of this bond will replace short-term borrowings, as no bonds are due this year, and long-term bank debt due by year-end 2011 is just €300 million. Thank you for your attention, and we'll now hand you over to Paolo for his closing remarks.
Gentlemen, before answering your questions, I would like to take a final moment to reinforce what I hope you will take away from this update and your visit to our operations here in the Republic of Congo. First, I hope that you will get a sense of how we work, our values, and our corporate culture. The dual flag approach runs deep within Eni, and its origins go right back to the formation of the company. Secondly, this approach is the basis of our success and prospects in Africa, a continent which forms the core of Eni's position in the global energy industry and is a key pillar of our sustainable upstream growth strategy.
Our project pipeline and the exciting new discoveries we have made mean we are now in a great position to deliver growth at the top end of our industry, not just for the next four years, but for the next decade. Third, we are backing our growth agenda with a robust financial platform. Growing production will drive cash flow generation, which will strengthen our balance sheet, finance our value-creating CapEx plan, and fund returns to shareholders in accordance with our confirmed dividend policy. Eni, with our asset mix, our technical skills, and our distinctive operating philosophy, is uniquely placed to prosper. I hope that this will become clearer to you during this visit. Let me now hand over to you for questions. Camilla, you will take the lead.
Hi, good afternoon, gentlemen. A couple of questions. The first one is, your CAPEX seems to be based on EUR 100 of the current oil consumption versus your cash flow pointing to EUR 70 per barrel. The difference there is the flexibility in your CAPEX. Trying to understand how much flexibility you have in the coming years on the CAPEX. The second question is on the area four on the Mozambique. You're talking about 10 to 20 TCF of gas in place, but I think the guys on the other side of the block are talking about 10 to, actually, more than 10 TCF of the core of gas. How do you analyze this?
Excuse me, Claudio, can you clarify a little bit more the first question, please?
The question is, how much flexibility do you have in your CAPEX between now and 2014?
Oh, Sandro, you answered the first one. I made the AWO overlap on the rest of it.
Our CAPEX plan, both for 2012 and for the subsequent year, is based predominantly on projects which are already ongoing, but we have a certain level of flexibility in our CAPEX plan. However, I don't believe that it will be necessary to rely on this flexibility because there's important.
Cash flow that we have been granted during 2011 and the cash flow that will be generated before year-end. I am really confident that we'll be able to catch the disposal that we have already finalized, and we'll be able to catch within year-end. We'll provide those funds which can support entirely our plan, even in a worst market environment. Answering to your question, we have some flexibility, but we are confident it will not be necessary to rely on such flexibility.
Block four, you know that we are drilling number one. The estimation, the figure that you were talking about, our estimation based on the structure and the seismic, is getting pace.
You started off the call talking about the structure of the business in the sense of both GAAP and the SLAM business. Clearly, the macro environment's not particularly conducive to selling assets at the moment, but also it's quite a good opportunity to buy assets when things are as distressed as they are. Could you comment a little bit on your view of the wider macro and whether or not that's a catalyst for you to accelerate potential restructuring plans, or is it a sort of a wait and see?
We're speaking specifically about GALP and about SNAM Rete Gas. Then we could speak more generally. We have seen that we have made a few asset acquisitions lately, including Edwin Franklin in the UK and Block 245 in Nigeria. No two acquisitions of assets which we have made exactly to exploit the right opportunity for buying. Moving to SNAM Rete Gas and to GALP. On SNAM Rete Gas, we have said many times we are not in a hurry of doing anything. I agree SNAM Rete Gas is not a business which is synergic with the rest of our businesses. That's true. It is a very complex business to dispose of for several reasons, including the fact that we are not completely with free hands. We need to have a decree of the Italian government.
This decree of the Italian government will happen only if the government is satisfied with the end result of any potential disposal of this business. We are very worried about making something which is shareholder friendly, both for the shareholders of Eni and for the shareholders of SNAM Rete Gas. It is a very complex operation to be made. We are not setting any date for the end of the story simply because the whole story is not completely in our hands, and we are more interested about doing something timely than doing something quick, if I may say so. On top of that, you know at this share price, SNAM Rete Gas is giving us a return of 8%, which is in excess of our WACC. Frankly, we don't feel obliged to do something very quickly. Now, GALP is a different story.
Of course, when we acquired the 33.34% of GALP, the total idea we had was not to resell it. It was quite the opposite. Our idea was we would like to be in this company because it is a small Eni, and we would like to integrate this small company with our business and to make it part of our company. This was the idea at the very beginning. Time has passed. It became quite evident to us that this idea of integrating the company with our activity was becoming difficult, difficult to implement. At the same time, the Brazilian operations of GALP, which represent probably 80% of the value of GALP, do not have any role in being the operator. We feel that we don't want to be just partners, even in a very promising area such as Brazil.
We have taken the decision that if we can find an appropriate buyer, an appropriate price, we are selling. Of course, from now to 2014, more exactly to March 2014, every buyer in practical has to be agreed by Mr. Amorim and also by the Portuguese government. Difficult times for selling assets. Difficult times for selling Portuguese assets, which also plays a role. Difficult times for complex operations. I have to tell you, we are quite optimistic about this deal, but probably less optimistic than we were a couple of years ago or 18 months ago. Aldo will tell you more if you want because he's running the negotiation.
I have nothing to add, Paolo, because you have already mentioned the critical points of this story. Of course, as already stated by Paolo during the presentation, we have interested parties. For sure, what's happened in August in the Eurozone has, let's say, generated more problems in the interested parties. They are examining in more detail, but I can confirm that there are still very interested parties. I don't know. I don't want to set up any deadline or the closing of the negotiation or the discussion, but for sure, there are interested parties, even in a so harsh environment.
It's Chelmsville News Investment Management.
Thank you very much for the visibility going now further out 10 years. We can see the various components of the growth engine. It is quite difficult to understand with the very substantial growth engine segments what's happening with the rest of the portfolio. Could you just talk a little bit perhaps about the assumptions you've got for decline in the rest of the portfolio? I mean, we've got a lot of new oil production coming on, which tends to decline a little bit faster. The decline rates, and particularly in the Republic of Congo, it's quite interesting for us being here just to understand really where you can take the recovery factor there because it's not quite clear to me what you're assuming with the underlying portfolio in order to, I mean, I think we're making more than 2% growth here.
I'm just trying to tease out the various parameters. The other piece that looks perhaps a little conservative to me is Kazakhstan, the assumptions for Paratagonite Phase 3 appear to give no growth. It is very difficult to see where further phases of the second phase of the cash gun kicks in. I have quite a few questions.
I was questioning about, I think that all I said and what I showed recently, it tells me immediately that in the growth, when I talk about Kazakhstan, I didn't put any emotional phase for cash again. I just put at the end of the period, the conversion phase. Just the difference between the EUR 370,000 per day that we reach with the experimental phase and the gap to reach EUR 450,000 per day that we can reach with the conversion. That's at the end. It's quite conservative. That is true. For Kazakhstan, there is phase three because phase three, I think, Kazakhstan, there is phase three with two or three years of shift. Phase three is quite mature in terms of starting and restarting to reduce costs. We are quite sure, as I said, that after the finalization of this negotiation, we can start and go ahead with the phase three.
You talk about Congo and you talk about what we think is that we can increase production in Congo. The recovery factor is quite diversified because we are a different kind of field. Also, in the mature field, we have a layer with a very low recovery factor from which we can increase the production with new techniques. Tomorrow, during the visit, I can explain to you more about Gachi, Luango, that are all fields that still have a lot of potentiality in terms of EOA. The average recovery factor of good field is about 25%, 28%. Still something that we can improve. There are some layers, some horizon where we can apply EOR with a recovery factor that is less than 10%. It's still 400 or 700 oil. I'm talking about oil in place. It's still there to be recovered.
I think that is, we have additional potential that we didn't need in the 3% for the long term. I agree with you that it's quite conservative, but it's true. It's quite conservative. We have quite a big contingency. We didn't express all the different potential. Also, because if we have knowledge of potentiality, there are some fields where we have to extend concessions. For that reason, we prefer to be conservative. I agree with you that we can get better results.
Just to finish up with what you've built in in terms of the expectation, the return on the exploration program, and also the underlying decline rates that you've got within the portfolio.
In terms of exploration, we are quite pleased. In the last three years, I think that exploration works very well. We probably see a potential effort to find all the critical people in production, and Angola is a clear example. Kitan in Australia or Joint Creek. When we start with the exploration with the sensitivity, I mean, we have already a development option. I think that really we can increase. Just to give you an example, if I remember well, in the last three years, 50% of the resources that we have found, for the 50%, we have a time to market that is around four years. In the previous three years, just with 35% of the resources that we have found at a time to market of four years. We are increasing the amount of research. We didn't capture all the exploration potential in this long term.
Also, from the exploration side, it's a conservative long-term projection.
I'm sorry, Claudio. This is Jon Rigby from UBS. Two questions, I think one for Claudio and one for Paolo, if that's possible. Claudio, just to go back on for that exploration point, I assume that within the next three to four years, you'll be spending exploration monies on things that you don't even, you're not really thinking about at the moment. Let us confirm that with your focus on cycle time and so on, is that potentially by 2018, 2019, 2021, is there going to be stuff coming up in the production portfolio that really you're not even thinking about now, just to kind of gauge how conservative that 10-year outlook is. On for Paolo, it's fairly clear, and I think the frustration of a lot of oil investors that your stock over the last three to six months has been impacted by the Italian sovereign crisis.
I wonder whether we could just take an opportunity to just survey where actually the sovereign issues impact Eni from a practical purpose and to what degree you think those problems are probably being over-exaggerated in the context of your stock.
Expiration only when you added and decide different targets so that we know that maybe we don't have yet acquired, but we know we have a clear target in the Far East, a clear target in West Africa. You know that we are the only ones that are developing the onshore pre-sold oil, and we are increasing. There are several reasons because we want to do that, but we are increasing our assets in that area and maybe in the future in North America. We are working, as I said before, to identify expiration with the already existing options in terms of development. We have different slots, and it's not inside this growth plan. That is for the next two decades that we're sure we're going to increase. I'm going to also add an answer because I didn't answer about the decline rate that I applied on this.
It's still between 3% and 4%.
Okay. Now, let me first say that, of course, I watch closely our total shareholder return performance as compared to what we consider our peer group. So far, we have been performing in the region of what has been performing two European competitors, so BP and Total, and worse than the Americans, essentially. Now, of course, I'm not pleased with the performance. In total, considering the Libyan situation, which has been hitting us more than anybody else in the industry, I always thought that we were performing reasonably, no, not reasonably, not too badly, not considering Libya. Now, to appreciate out of our performance, how much is Libya? How much is sovereign Italian debt? For me, it's fairly difficult. You know, these things are always quite difficult to understand what is what. In total, as of yesterday, our total shareholder return yesterday was better than BP and better than Total.
I said, not too bad, not too bad. Of course, to see our share price at €13 paying a dividend of more than €1, seems to me awkward. Probably my colleagues would say the same about their share price. I imagine, I imagine. It is the whole industry which is suffering probably too much considering that our business is doing fine.
I just wonder whether from your position, whether you could kind of reassure us or comment on actually the practical issues in terms of the problems that the state is having and how that actually impacts or doesn't impact the company.
No, look, the only impact we had is very much an indirect impact that we had through this new task called Robin Task on SNAM Rete Gas, which we own 52%. If I remember, in terms of net profit, the hit on SNAM Rete Gas will be in 2011, €150 million. For us, €75 million of potential dividend since we consolidated €150 million. Fairly small numbers for the timing. Of course, we don't like it, but it is a relatively small number for us.
Thank you for the presentation, Mrs. Mukhtar Gargaghi from Citi. First of all, question on Russia. It seems like it's becoming a bigger and bigger part of the portfolio. Can you please comment on the economics of those projects, especially given that things are very vague with Gazprom pulling exports, internal pressure on the company? How do they compare to your global portfolio overall and how are things looking in general? A second question in Iraq or Zubair. Lots of companies are commenting on problems with ramp-up of production. How is it in Zubair in Iraq? Are you maintaining your guidelines the same as before or do you think you're going to face delays as well? Thank you.
Let me explain something about Russia. I may leave Claudio to give you some more details about Zubair. Now, on Russia, let me give you the elements of the whole thing. First of all, you might remember that we paid our reserves EUR 0.60 a barrel. Now, EUR 0.60 a barrel is not a big price for which we negotiated in 2007. The CapEx we are going to make to develop those barrels are around, I think you gave the number before, EUR 3 per barrel. It's EUR 3.5 per barrel. This is our cost of production, including the initial cost plus the development cost. Of course, it's EUR 3.5. I'm going to call that EUR 4. EUR 4. EUR 4. Around EUR 4. Okay. The total cost is fairly limited. What do we produce? It's gas and condensate. Condensate, we have an international price, so no problem whatsoever.
As far as the gas is concerned, we sell the gas to Gazprom at their average selling price. Their average selling price is the compound sum of what they sell to export, more or less one-fourth of the gas they produce, and what they sell domestically, the other three-fourths. In total, now making all this reasoning, this project is in line with the IRR we have on all our projects in...
We didn't talk about the word during this presentation. We didn't put in any of our strategic cards. First of all, just to talk about future, we consider us a group of fields that can deliver production about 150,000 and 200,000 barrels a day on a constant rate. Today, after the full development, can reach a peak of equity production of about 110,000 barrels per day. Once we have the cost, it keeps an average between 40,000 and 50,000 barrels per day. It's not in this range at the moment. Talking about the performance of this year, from an operational point of view, it's going very well. No problem at all. The only issue that you know, that is the practical APHC you have to spend to recover cost to increase your equity production.
What has happened is that I give you a figure very clear that we had a gross budget, the overall gross budget of EUR 3 billion, and we spent EUR 700 million. That means that we were not in the position to deliver again the equity production because we are not able to spend all the money that we reported. That's why. We are in a process of learning and not just some of the history is learning, and we are in a transition phase. The bureaucracy and the time to market for awarding a contract is not really what is written in the contract, in the service contract we signed. I think that in the future, we are positive we can improve, but that is the main reason. Bureaucracy and learning process for everybody. The integration in the S3 company with the Iraqi people and the operations are going very well.
Security, I touch across the fingers, positive. Not a big problem. We have more than 200 people in the camp. We had a new camp, and we drilled 15 wells. We are work order. We are depot-making a lot of lines. We are working positive from that point of view. The budget due to the spending is not so good in terms of production.
I have one other very interesting point of question. I have a question and a follow-up on John's question on the European crisis. One is more like a financial one. As a company in another sector, aside from the treasury, we've got Greek bond. I want to make sure that we have no Greek bond in your treasury. Just as an information, it seems that other companies in the sector have paid by Greek bond, and other customers have to do some provision. A follow-up is more on the demand side. For instance, for your gas business, before year end, don't you think, because my understanding is that gas demand in Italy, for instance, is decreasing since the beginning of the year. The stock of gas is high, higher than last year. The oil price is decreasing.
Do you expect before year end a decrease of gas stock, and as a consequence, it's going to have an impact on your gas sales? The other part of the question is for next year, how do you see the gas demand evolution in your business plan? Do you think that what type of assumption do you take in terms of volume gas demand for next year and for market share gains? Do you think as a consequence, my understanding is the industry part of the business is decreasing next year. There is a risk that the minimum level of gas take from Russia is going to be higher, and as a consequence, we need to forecast a cash outflow. My last question should be on Indonesia. I have a look on your slides that you expect a decrease of LNG cargo or energy production in Indonesia by 2013.
One of your European peers is saying, holding his analysis day a week ago, and he's saying the same trend. In Indonesia, our production of LNG is going to decrease in this time of period. If I had to look to the Asian basin, Australia will not pick up before. Do you think that you were going to the Asian LNG market will be buoyant in 2014?
On the first question, I don't think I need assistance of Sandro. We don't have the Greek boundaries only I spoke to.
Sure.
No, there is no bond to us. We issue bonds. We don't buy bonds. Now, on the gas, you made lots of questions around gas. Of course, first of all, I would like to reassure you, stocks are very high today as they should be because we are entering into the winter season. Always, stocks in Italy and everywhere in Europe at the end of September, beginning of October are at maximum. The maximum you can stock is there. Nothing really commercial is all around winter season and summer season. Trust me, what will happen with the stocks, will you use the stock or not? This will depend on the weather. In cold winters, yes, we use almost all the stock in Italy and elsewhere. In warm winters, this does not happen.
In terms of consumption of gas, consumption of gas in the first part of the year in Italy has been better than last year, more than last year. Generally speaking, in Europe it has been good. Of course, if we foresee a decline in industrial consumption for the future, then consumption might not increase as we expect. As far as take or pay, you mentioned take or pay in all these kinds of things, the clauses which regulate take or pay are part of the renegotiation we are doing now. It is a piece of our renegotiation. That's just for because maybe not every one of you understands exactly what the take or pay is. I know this is very much a specific issue and normally you don't encounter it in the oil industry. The first take or pay we paid was in 2009.
A small amount, I don't remember now the number, €300 million. If we were to sell the gas we prepaid in 2009, we would be making a big profit. Let me try to explain to you. When you pay, because you didn't take, if you didn't take, you pay. What do you pay? You pay in anticipation a small amount of the gas you didn't take, like 30%, the gas you didn't take, and you fix the price, which was the price of 2009. If we were to sell that gas today, we could make a quite big profit. No, because people have in mind take or pay equals bad. No, take or pay is simply buying today something you don't use today, which you have 25 years of time in front of you to use.
Therefore, if you forecast that in 2020, the gas price would be double than it is today, take or pay is a positive, not a negative. Just to give you this kind of new look at it. Not to say that I like the take or pay. I'm just saying it's not necessarily a disaster. I think I answered about the gas. Now, of course, let me give you just an element for us. For us, Libya is extremely important because of the three big contracts we have, four big contracts: Norway, Libya, Algeria, and Russia was the only one we had already renegotiated in August last year. We renegotiated the contract so it was a contract more, let's say, closer to the current prices, to the current stock prices, and it was interrupted. Every month in which we can have this gas flowing is a positive.
We said that we are fairly optimistic about Algeria. Russia, we are not pessimistic, but we need some more time. In total, all our strategy is to move this contract to be more coherent in the scenario of stock prices in Europe even next two to three years. Now, for Indonesia.
I know the LNG market in Paris needs to improve, but not really enough chain.
LNG.
No, LNG.
No, no, no, no. LNG in the Far East, demand is extremely strong. Prices are very high, much higher than spot prices in Europe, four times prices in the U.S. This is the reason.
Yeah, I'm buying it myself.
Okay. We do not see demand picking up very soon. Demand will continue to grow in the Far East. Now, of course, you know that we are involved in sharing gas in China. If China will enter into the era of sharing gas, something might change. This is not for tomorrow. We take a few years.
Hi, it's T-Pan from Unira. A few questions, actually. First, just sticking to LNG. You've got a couple of potential areas where you may start up new projects, Ghana and potentially Mozambique. I was just wondering what are the next steps in terms of Ghana before you can make an FID? Do you have enough resources? It's quite noticeable that with many of your projects, you don't have a huge stake. I was just wondering whether you're comfortable being the operator and having such a large stake in an LNG project. The second question is probably for Talo, but it's following up on sort of what we've discussed already around the sovereign crisis. I guess it's noticeable in some ways that Eni does have a high interest or ownership from the government. I was wondering, Talo, is that helpful, unhelpful?
I was just wondering what sort of restrictions there are on the government selling down a stake?
Maybe you want to talk about that. I say something about LNG in general. For the prospects we have found, or I hope we have found something, we have a big stake in the operatorship. We don't have a small stake because in Mozambique, they have 70% of the operatorship. In Ghana, we have 50% of the operatorship. Going to Ghana, yes. What we have found until now is enough for a trucking energy. We're considering enough for a trucking energy about 2.5 to 2.4, 2.5 this year. That is what we consider. Already, Shell, I think that is at the edge. Eni, we already produced some trucking energy for Australia, Indonesia, and the Gulf of Guinea.
In Ghana, considering the resources that we have found, we have enough gas to develop a floating LNG of about 2 million, 2 million tons per year, and also delivering gas to the domestic because one of the main targets for the Ghana government is to build a power plant. These two main projects are to fuel this power plant. One is an existing one in production, in the BDE that they are associated with us, and they already started the first phase with the Ghana government. The second one is our block.
Sorry, just to follow up there, would you be happy to develop those types of high interests?
Yeah.
Thank you.
On the sovereign risk, listen, here are two answers. First of all, I never heard any political man in Italy proposing to sell down the stake of the government as Eni. Now, it might change tomorrow, but so far, neither in the government, nor in the opposition, anyone has been proactively proposing this. Second answer, I have to tell you that maybe I got used to it, but frankly, I don't notice any difference. I've been running a public company for, by the way, a British public company for more than six years. If you ask me, is there anything different? No, I don't feel any difference at all. The government, of course, comes in the shareholder meeting and so far has been appointing six directors out of nine. I say so far, but I'm not sure next time this will happen because shareholders show up now.
At the last shareholder meeting, we had more than 20% shareholders, guys like you, showing up because since you don't have any more to deposit the shares, then people show up. It might be the case next time. It might not be, but of course, we don't know. I have to tell you, I consider all this fairly irrelevant because after the shareholder meeting, in which the government, of course, plays a role, we become a company like any public company in Europe. We don't hear from them anymore.
Hi, Oswald Pantone from Princeton. Just back on the subsoil exploration, it's a big focus of today. I just want to know, are you doing anything different or how are you preparing for subsoil exploration? Do you have any experience? Are you drawing from? Is there any involvement with the Brazil successes given that you want to try it here in Sub-Saharan Africa? It's clear that obviously not everybody can make this successful. Much bigger companies have been unsuccessful. Also, again, just back in Norway, I noticed the different profiles for Goliat and Skrugard. Skrugard seems to have a much more stable production plan as you look out versus Goliat. Goliat seems to fall off quite quickly. Is there anything there with the development plan or the reservoir that we should know about? Thank you.
Thank you. First, pre-salt, subsoil to pre-salt. It's probably a bit pre-salt in Angola 25 years ago because all the Block 0 is pre-salt. That is, we have some experience. The Block 10 in Republic of Congo is pre-salt, Marine 10. What we are doing differently is that we are following the pre-salt horizon onshore. That is the main difference. We have also some blocks like Block 35 that we got a few months ago in Angola, but we are really focused on the onshore West Africa pre-salt. That is, we got a stake in North Cabinda. We are finalizing Cabinda Central. We are in Democratic Republic of Congo. We are in Republic of Congo producing and re-exploration. We acquired four blocks in Gabon. The strategy, a strategy that comes from a regional study and comes from a model that we set up some years ago, and we are following.
In Bundi, since we acquired Bundi, with this kind of model, we passed from, I'm talking about oil in place of 1.3 something billion to 1.9 billion. We discovered in the last, starting from 2007, more or less 400 million of oil in place additional on the pre-salt. I don't know if we are doing something different from a technical point of view. We are doing something different from onshore. We are following the onshore. We are getting a specific experience in this area. Sorry. I'll do yet, I'm Skubet. Skubet, I just got one way. Goliath has improved development, has been approached, has been studied and restudied. Eni as the third we discovered. I think the statistics and the experience of Goliath, the internal future production is there more than Skubet. I hope that Skubet would be better for sure.
What I know from E&P, you know all the good shield of different phases of development, and we have the E&P uncertainties because we developed something that is 4,000 or 6,000 meters underground. We know that we never have just one phase. I hope that developing Goliath, this is a figure of this kind of reservoir that is not very strong in energy. That is really a natural depletion phase. I think that we can find an additional possible mechanism to increase the recovery factor.
This is Gloria Palladini from the IR department.
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Good afternoon. It's Rahim Karim from Barclays Capital. Two questions, if I may. The first one is just on the upstream. A lot of focus or much more focus now on the unconventional part of the portfolio. A lot of gas within that. I was just wondering, all assets seem to be here in Republic of Congo, whether that's a large enough exposure to oil and whether you might be looking to expand that elsewhere globally with the Union and Venezuela as well, whether that's enough for you. The second part was on gas and power, just a clarification. It sounds like the negotiations with Russia seem to be delayed slightly. I just want to double-check that the benefits or the restating, even if it does go into next year, will stand in place and that you will get benefits from that going forward.
Okay. Okay. Unconventional. Just to wrap up, because I was talking too very good, and it's really not unconventional. It's AVR, but it's absolutely not unconventional. You have a lot about it. Oil, you know, gas unconventional, like gas unconventional and oil unconventional, we had an unconventional approach. We didn't want to go to Canada. We didn't want to go to the States acquiring a huge amount of unconventional gas just to learn. As I said during the presentation, in a country or an area where we have synergies, where we did market, and we can grow, and we have less competition, and we can grow rapidly. For oil, just Congo, because Congo is, like Roberto said, a very, very good opportunity in terms of oil. That is a very good oil. The gas, because for the future upgrader, you know we have to use a lot of gas.
In other countries, you have to buy gas. In this case, it is a clear gas that we use. It's going to reduce the drastically cost. If you look at the marginal cost, for example, in Canada, marginal cost for AVR in % goes from EUR 80 to EUR 100 per barrel. Our marginal cost in Congo is between EUR 50 to EUR 60. We have really the gas that is free and creates a big advantage. We use our upgrader. We have all the facilities in terms of treatment and in terms of terminal. We try really to build on what we have. That is a different approach. I think that tomorrow we're going to visit the area where we plan to develop in the future this Touchland field. That means how we are moving.
We reduce risk, we reduce cost, and we try to be more efficient in terms of pencil market because we have already facilities and know all the area. Okay. On gas, I won't say that our negotiation with Gazprom has been delayed. I would say it's a long negotiation. On the other hand, you might be aware that they are going into arbitration with AEON, RWE, and BOTAG, Turkey. Of course, the arbitration is always a possibility. I consider that it is a possibility everyone should try to avoid and they are probably negotiate. We can negotiate in good terms. Let's say we are not pessimistic about the outcome of the negotiation. Of course, any negotiation with Gazprom will be fixing a price from January 1, 2011 as any negotiation with Sonatrach will fix a price from April 1, 2011. It will be retroactive.
Hi, it's Stan Hawkins from RF Global. I was going to ask you to take that question on Gazprom, but just to follow up on that, if it were to go into arbitration, what sort of timing would we be looking at for resolving? It's really, really rough. I know it's a what-if. The second question, just on social investment, and I guess that's particularly relevant here in Africa. I mean, how do you decide where to draw the line in allocating capital to social investment? How does that play into some of your maybe the power sort of screening criteria, especially given the healthy returns you can get at EUR 100?
On the first point, luckily, we don't have much experience of arbitration against Gazprom. Neither us nor anybody else. We are into really unexplored territory. Arbitration is made in Sweden. Arbiters normally know nothing about the business of gas, so they are moving into very legal kind of issues. The best forecast, because I asked the same question as you, and the best forecast I received was a couple of years. What I don't like, apart from the fact that in two years, you know God only knows what happened in Lapland, is that just for two years, you are selling a gas of which you don't know the price. It's really something we don't want to do, frankly. That's the reason why I will do my best to end the negotiation positively. On Algeria, we are in good shape, we think.
I hope to be able to say that we are in good shape with Russia in the next few weeks. Oh, sure.
There is a question from the online conference call. It's Mr. Jason Kenny from Santander. Mr. Kenny, please proceed with your question.
Hi there. I hope you can hear me. It's Jason Kenny from Santander. I just had a quick question on whether you were still optimistic for China Shell gas and how you see developments there impacting the Asia-Pacific LNG and gas markets. Secondly, if I can, there's potential for your free cash flow to push down gearing quite significantly by the end of 2014, going into 2015, particularly if your divestments of either GALP or SNAM were included as well. I'm just wondering if you had a target gearing level on a through-cycle basis.
Maybe I can answer quickly your question, then if Claudio has something to add. As far as China is concerned, very early days to say what we think about the potential for shale gas in China. No, for the time being, we don't. We believe that is a cost.
No, of course.
No, we believe that there is. For this reason, we made an MOU and we are investing, but it's early days to define what is the potential. Would you agree on that?
Absolutely.
Now, as far as gearing is concerned, the only target we have for the time being is to go back below 40%, which has been our target for many years. That's the only target we announced, and all this by the end of 2014.
Okay, no, thanks.
Excellent. Excellent, that's the other aspect.
About social, when you talk about social, you mentioned also the power plant. The power plant is social as a byproduct. It's an industrial project. We want to reduce, as a first plan, we want to reduce flaring and monetize gas. We also have to take a commitment in the country where we live. When Paolo talked about double flagging, that if I go, I can also make the choice to develop the domestic market. That is the best way to give sustainability and defend our presence in the country because the only way to be credible is to take some risk. It's a risk that is analyzed and followed up. It's clear that we don't throw away our money. The Nigeria power plant was a very successful one in terms of result, in terms of relations with the government, in terms of recovering our costs.
Now we are replicating this example in Republic of Congo. We are starting the living production. It's a social project as a byproduct. The other social project, like the Green River project that we developed very successfully in Nigeria, we started in 1986. It's something inside and covered by the contract that we have in the country. We cannot do anything. We are not a foundation. We cannot do anything outside the contract that we have with our first party. It's clear that it's something outside our core business. We put money. We have to demonstrate that we are doing well. It's a long process. The first party in Cairo, Nigeria, an NPC, DPR, the local stakeholder, there is a committee, a follow-up committee where to present our budget. It's a very complex procedure that started, is covered by the contract.
There's a question from the online conference call. Mr. Iain Reid from Jefferies. Please go ahead, sir.
Hi. Paolo, it's Reid from Jeffries. Two questions, actually. Firstly, you mentioned that there's no damage to the Eni facilities in Libya, but there was a story on the newswires today in London that the Elephant field is being severely damaged. In fact, I think the quote was, "It's in ruins." That was quoted by an Eni representative in Libya. I just wonder if you could comment on that and what that might mean for the resumption of production. The second question is on SNAM. Is it really possible for you to sell your stake to anybody apart from an Italian institution, whether that's a company or the government? Is there really any appetite there for taking on this sort of liability or this sort of cost at this particular juncture, given the crisis in Italy at the moment?
Okay. Now, listen, on the first question, let me answer what happened to our facilities in Libya. Everything which could have been removed has been removed. That is vehicles, computers, pumps, generators, etc. All this has disappeared. Furniture, of course, etc. Everything which could not have been removed has not been removed. That is, nobody tried to damage installations. No damage on purpose. Simply facts, people removing what was removable. This is true for all the fields, including fields and Elephant. Now, of course, you understand that when removable things are very small things in our investment and very easy to replace. That's the reason we are optimistic about resumption of production, with one caveat, with one question mark, that is security because I don't take security for granted in Libya.
If security becomes an issue, everything I'm telling you about resuming production, doing fantastic things, I will take it back because security comes first. Now, in terms of SNAM, realistically, I think that the only one possibility I can see as a potential controlling shareholder of SNAM is gas to deposit depressed. This seems to me realistic. We might dream other solutions, but we are in the area of dreams, not in the area of things which are likely to happen. That's the region in which we are exploring to find a solution.
Thank you.
Hello everyone.
We have no more questions from the call. Perhaps we can bring this to a close.
No more questions from the call.
Thank you, gentlemen. I just wanted to say that I'm leaving you with Claudio, Sandro, Roberto, the whole team. Unfortunately, I have to fly back to Milan, but I'm sure you will enjoy because the Congo is the perfect example of everything we do in Africa. It really is the example of the file, yes, which we do everything. Thank you.
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