Give you my view on our last year performance. Considering that 2013 was a year of real challenges, our results were reasonably good. In E&P, the drivers of Eni's profitability, production was disrupted by exceptional events. The resurgence of internal conflict in Libya impacted oil production throughout the year, as well as causing the shutdown of our onshore gas operation in the country in the last quarter. Rising oil bunkering also affected production in Nigeria. In addition, startups, including Kashagan, did not contribute as expected. In the mid and downstream businesses exposed to Italy and Europe, we faced very weak demand. This has been the result of the underlying economic situation in the continent. Consumption of oil and gas in Italy, for example, was respectively 24% oil and 18% gas, lower than the pre-crisis levels.
On top of this, our gas margins were further squeezed by the increasing availability of cheap spot gas and even cheaper coal, and by the strong competition of renewables. Refining margins were badly affected by the weakness of oil product prices and by the narrowing of the light, heavy oil differential, which impacted the economics of our complex refineries. Finally, as you very well know, Saipem had a very challenging year. In the context of these strong headwinds, Eni generated resilient profit and healthy cash flows. Focusing on cash flow, our performance was the result of four main factors. First, the underlying strength of our E&P portfolio. Thanks to our low-cost position, we continue to deliver an average cash flow per barrel of around $30. Second, the ongoing turnaround in our mid downstream businesses, which delivered a EUR 2 billion improvement in operating cash flows.
Third, our disposal plan, and in particular the Mozambique farm down, which is an example of accelerated monetization from exploration success. Lastly, our continued capital discipline with overall investments in line with historical levels. In total, we generated a free cash flow of more than EUR 4 billion, supporting our progressive distribution policy without impacting our financial position. Turning now to our 2014-2017 plan, we do not factor in any material improvement in market conditions. In E&P, we expect oil prices to decline progressively to $90 per barrel in 2017. We are penciling in Libyan and Nigerian production at 2013 levels up to 2015, with gradual progress in following years. In gas and power, we see flat demand in Europe and in Italy. In addition, Italian gas prices come under further pressure in 2014 as older B2B contracts are renegotiated.
In R&M, we see consumption of oil products at depressed 2013 levels, with small improvements in margins driven by the progressive reduction of refining capacity. Lastly, in chemicals, two different trends. In base products, commodity products, we see increasing competition from low-cost gas-based production, while in specialties, we see growing demand and resilient pricing. In line with this cautious market view, our strategy focuses on a selective growth in upstream and a material restructuring of our mid downstream businesses. All of this will increase Eni's cash flow from operations by 40% in the first two years of the plan and up to 55% in the final two years of the plan. Let's look at how in more detail. The biggest driver of our operating cash flow in the plan will be, as you would expect, E&P. Upstream strategy is focused on organic growth of low-cost conventional assets.
Our exploration will continue to feed superior reserves replacement, enhancing portfolio flexibility and strength, and maintaining costs at a very competitive level. To give you some color, the resources discovered since 2008 are equivalent to 2.5 times our production in the period. This success continues, as highlighted by the giant discovery Congo announced today. Thanks to the breadth of our portfolio, we will monetize some discoveries of even producing assets without affecting our longer-term growth prospects. We have already started on this path. In the past 12 months, we have cashed more than EUR 6 billion from upstream assets, a minority stake in Mozambique Area 4, and Arctic Russia. In spite of these asset sales, and of proven expectations in Libya and Nigeria, we target production growth of 3% a year to 2017. Our upstream production growth is also very profitable.
First, new production will be high margin, delivering an annual growth in operating cash flow of 5% at our planned scenario, declining oil prices, and a growth at 9% at $108 flat. Second, we will achieve this growth without any increase in CapEx. Indeed, investments will actually go down by 5% compared to our previous plan, thanks to the prioritizing and rephasing of growth opportunities. Turning now to our mid-downstream operations, we target a return to profitability excluding any improvements in the scenario. Our turnaround is based upon adapting our contracts and assets to the current tough market environment through renegotiation of the contract, capacity cuts, and operating optimizations. Secondly, focusing our presence on resilient markets. We target overall EBIT and cash break-even in 2015, and over the plan period, these businesses will generate an accumulated EUR 3 billion in operating cash.
Let's look at each business in more detail. In gas and power, our turnaround is based on three pillars. First, the renegotiation of our entire supply portfolio. We target further significant benefits on top of the EUR 1.4 billion contribution to EBIT, which our renegotiations delivered in 2013. As announced last year, our supply costs will be fully aligned to market levels by the 1st of January 2016. By market levels, I mean spot liquid markets across Europe. Second, the continued development of our premium businesses, LNG, trading, retail sales, which will deliver EUR 1 billion EBITDA by 2017. Finally, the re-engineering of the whole business, aligning it to new market conditions by streamlining logistics and cutting fixed costs. We target EUR 300 million of savings in these areas by 2017. As a result of all this, we target EBIT and cash flow breakeven by 2015. Turning now to R&M.
In R&M, we will cut further refining capacity in order to tackle the persisting overcapacity in the Italian market. This will bring our refinery's utilization rate up to 80%. Secondly, we will run an efficiency program across the board on logistics, labor, and fixed costs. Lastly, we will fully exploit the synergies with our trading arm to enlarge our feedstock base and take advantage of oil price differentials. The result of this action will be an increase of about EUR 700 million in EBIT, EUR 700 million, which will become positive in 2015. In Versalis, our chemical business, we made excellent progress on each of the three pillars of the turnaround plan we started in 2011. Firstly, reducing commodity chemicals capacity. We've already cut it by 25% through the conversion of Porto Torres into biochemical plant, the downsizing of the Priolo cracker.
In addition, we reacted to the economic slowdown that impacted the automotive sector, specifically tires, by reducing our exposure to elastomers, announcing the close of Hythe in the first quarter of 2014. We will further trim our capacity by 5%, mainly through the downsizing of the Porto Marghera cracker. Secondly, refocusing on more profitable products. By 2017, we will have increased our production of premium products, such as elastomers and styrenics, by 50% compared to 2013. Lastly, increasing our exposure in fast-growing markets, and in particular in the Far East, through our Malaysian and Korean joint ventures. As a result of all this, we target EBIT break-even in 2016. We will achieve cash flow break-even in 2015. Our strategy will deliver significant improvement in operating cash, driven by high-value E&P growth and by the return to profitability in our mid- and downstream businesses.
Starting from the EUR 11 billion in 2013, our annual average cash flow from operation will grow to EUR 15 billion in 2014 and 2015, each of the two years, a 40% increase, and to EUR 17 billion in 2016-2017. In addition, we have earmarked EUR 9 billion of disposals over the plan, which include the cash-in from Arctic gas already completed. We expect this divestment to be mostly front-end loaded. The growth in our cash flow from operations, coupled with asset disposal and reduced CapEx profile, will result in a 13% increase in annual average free cash flow versus 2013. In case of a flat-plan scenario, this increase of 13% would be 45%. Let me now hand you over to Claudio for a closer look at our upstream strategy.
Thank you, Paolo. Good afternoon, ladies and gentlemen. The main objective of today's presentation is to give you more insight on our distinctive E&P model, our short and long-term targets. This model is the basis for our strategy to overcome industry challenges in containing costs and generating free cash flow. Before speaking about it, let's have a look at 2013. This year, we recorded our best performer in HSE, with a total recordable injury rate 60% lower than the previous six years and zero blowout for the 10th consecutive year. Our exploration performance continued to exceed expectation with about 1.8 billion barrels of discovered resources at $1.2 per barrel. We achieved all the eight planned major startups, and we took seven main FIDs, adding to reserves for more than one billion barrels. The new startups, and ramp-ups , contributed 140,000 barrels per day to our production.
Last year, our production was lower than in 2012, mainly due to geopolitical reasons. Disruption in Libya, Nigeria, and Algeria caused production losses for about 110,000 barrels per day. Notwithstanding these issues, our net profit and cash flow is still very robust at the level of EUR 6 billion and EUR 13.4 billion respectively. To frame our action plan, a few words on the industry context. Over the last few years, the upstream industry has faced two key issues, a strong increase in total expenditure and a poor production growth. Since 2008, the majors' expenditures have increased by about 40%. This was mainly due to big M&A transactions on unconventional plays and increasingly costly projects. This caused a worsening in the self-financing ratio of our peer group of more than 20%.
In the same period, Eni has recorded a 20% saving in cost incurred, which translate into a corresponding improvement of our self-financing ratio. What has made this different trend a result possible for Eni? This has been possible for four main reasons. First, we have focused mainly on organic growth from a conventional asset base with no major M&A transactions. Second, our outstanding exploration has given us an efficient cost structure, ensuring solid cash generation. Third, the timely transformation into production of our huge discovery through a phased approach to investment, which allow us to reduce upfront financial exposures also for giant projects. Finally, our producing asset, the main area of cash generation, where we achieved best-in-class operating cost and superior recovery factors. Now I'm going to elaborate on our planned target based on our model.
In exploration, our objective is to continue obtaining the excellent result of the last six years following the same approach, targeting conventional assets. To do this, we have renewed our portfolio with two main priorities. The first is increasing our acreage on emerging basins. In East and West Africa, where we target mainly gas in Mozambique and Kenya, and oil in Congo, Angola, and Gabon pre-salt. In the Pacific Basin, where we are concentrating on oil and gas in Vietnam, Myanmar, Indonesia, and Australia, and in the Arctic, where we target oil in the Norwegian and Russian Barents Sea. The second priority comes through a major review of our legacy assets, where we apply a new geological play concept and leading proprietary technologies. We have already achieved exciting results in Angola, Indonesia, Egypt, and Congo.
A remarkable example of this approach is Marine XII in Congo, where we recently discovered more than 2.5 billion barrels of resources in place. Through this discovery, we cracked the code of the pre-salt in Congo. This achievement was the result of deploying Eni leading proprietary technologies to an asset which had already been explored since the 1970s without revealing any discoveries. The block operated by Eni, with 65% stake, is in the shallow water, only 17 km from the shoreline, and close to our existing offshore facilities. The Nene Marine 3 well has found very good quality oil, and during the production test, the well delivered more than 5,000 barrels per day. In addition to the 2.5 billion barrels discovered, we expect further oil and gas potential, that we will assess through a dedicated campaign starting this year.
The proximity to existing facilities, high volumes, good productivity, and low cost will bring the new discovery to production already in 2016. Our new portfolio, made up of new emerging assets and the revisited legacy ones, give us prospective resources of about 10 billion barrels, of which we are targeting 3.2 in the next four years at a very low cost of about $2.20 per barrel. In our model, cash generation starts from exploration, where we apply a dual approach. On one side, a major portion of these resources will be developed to ensure high-margin organic growth. On the other side, some of the resources can also be used to ensure early cash in through dilution opportunities. This strategy is achievable also because of our very high participating interest in all exploration assets, currently in the range of 50%-80%. The Mozambique transaction is a result of this model.
80% of these huge exploration successes of the last six years will be developed in less than seven years. The strong focus on time to market as a first key step, the timely sanctioning of our projects. In the next four years, we will take 18 major project FIDs, mainly in Sub-Saharan and East Africa, and Southeast and Central Asia. This effort will deliver 3.5 billion barrels of 2P reserves. In the four-year plan, we will put 26 major projects into production, more than half in the next two years, contributing about 500,000 barrels per day in 2017. These projects are geographically well-balanced, mainly throughout Europe, Sub-Saharan Africa, East Asia, and the Americas. Here you can see an update on how we are progressing on the main sanction projects. All are on schedule with only a few minor delays and very low cost overrun.
We ensure a strong grip on our project by conducting most of the engineering in-house through a reinforced organizational structure. We directly coordinate all the construction phases and deploy our own people to manage hookup and commissioning. The result of this is a project portfolio where we have better control, reduced risks, and contained costs. Now an update on some of our major projects. The Kashagan experimental program was completed and commissioned, with first oil achieved in September. The well was on stream, and the overall process and critical components were performing well. During the initial production, cracks were discovered in the gas pipeline. A thorough investigation identified a root cause, and we have been carrying out intensive repairs to reinstate the pipeline by the middle of the year.
At the same time, we have brought forward the commissioning of the Train 2 and the gas reinjection compressors, having more than three months of shutdown. Allowing, once the gas pipeline is restored, a faster ramp-up of production without further interruptions. In the event the gas line restart is delayed, the gas reinjection will make oil production possible. Goliat is one of our major projects. The Barents Sea is a very challenging environment that has required us to build the biggest circular FPSO ever, the first of this kind to be deployed in this area. The project has reached 71% progress, in line with the plan. Drilling and completion activities are progressing in line with schedules. The FPSO construction in Korea is at 89%, and the sailaway is expected in second quarter this year.
Production startup is expected by the end of this year, and the equity peak production will be 56,000 barrels per day in 2015. Looking beyond the four-year plan, Mozambique will be a pillar of our medium-term growth. We have completed the exploration phase, Mamba complex, with 11 successful wells. Potential stranded resources account for about 50 Tcf of gas in place, while about 35 are fully included in Area 4, thanks also to our new discovery in Agulha. This year, we plan to drill one appraisal well and one exploration well. Considering the significant amount of newly discovered resources, an enhanced development scheme has been defined with a total capacity up to 17 million tpa.
For Mamba's stranded resources in Area 4, where unitization has been agreed, Eni is planning one initial onshore LNG train, plus two floating LNG units with a total capacity of 10 million tpa, and an option for a further onshore LNG train. Eni is also ready to launch the development of the resources of Coral through a floating LNG. We confirm FID for the first phase by year-end, with startup in 2019. Our project portfolio is largely made up of onshore and shallow water assets with an average breakeven price of $40 per barrel. Even deep and ultra-deep projects have a very robust economic, with an average breakeven price of $55 per barrel. Our project has very robust also in term of cash generation.
Considering 2013 ramp-ups and the four-year plan startups, net cash flow will be positive starting from 2015, reaching a contribution of more than EUR 4 billion in 2017 and in excess of EUR 6 billion in the mid-run. Our existing producing assets remain the main source of cash flow and will account for over 70% of total production in 2017. In order to extract the maximum value from this crucial assets, our objectives are to fight depletion and prolong the life of our fields with an average target of 70,000 barrel per day from production optimization project, reduce facility downtime to less than 6%, increase recovery factor with a target of 43% for oil and about 70% for gas. Now the 10th main objective. In the next four years, we confirm a production average growth rate of 3%.
Our 2014 production is flat versus last year's, excluding the disposed Russian production. This takes into account no improvement in Libya and Nigeria and the marginal contribution from Kashagan. Our performance could improve materially if geopolitical disruption are less impactful. By the end of the plan, we will record a major contribution from West Africa, the Caspian area, and East Asia, with an overall production target of about 1.8 million barrel per day. In the longer term, major project in East and West Africa, the Americas, and East Asia will sustain an annual growth rate of 4%. In the next four years, our spending will be 5% lower than in the previous plan. Thanks to the rephasing of our project investment. Our rich exploration portfolio allow us to do this while maintaining production growth and targeting an increase in cash generation.
We expect to meet these cost targets for the following reasons. 80% of our project investment have already been sanctioned, and most of the procurement contract have been signed and the cost locked in. An additional 25% will be sanctioned this year. Second, we have the lowest exposure to complex projects. Only 20% are in costly areas, such as LNG and ultra-deep water. On exploration, we will continue to invest in line with our previous guidance. In conclusion, our main objective of sustained cash generation is based on our distinctive model, which defines our competitive advantage. First, we have a robust economic structure with a cost per barrel of less than $30, made up of outstanding exploration and efficient project development and resilient producing assets. Second, over the years, thanks to capital discipline and operational efficiency, we have maintained an outstanding self-financing ratio above 100%.
We intend to increase this to more than 140%. Leveraging on these factors over the plan period, we are in the right position to increase our cash flow from operation and our free cash flow by 9%. Thank you for your attention. Now I hand over to Marco.
Thank you, Claudio, and good afternoon. I would like to begin by highlighting the main events that took place in gas and power in 2013. Starting with our take-or-pay contracts, last year, we managed to reduce our supply costs by EUR 1.4 billion, which is better than we had expected. We reached agreements with all our major suppliers, representing around 85% of our portfolio, with the exception of Statoil, with whom, as disclosed, we entered into an arbitration in August because we were unable to find an acceptable solution. On volumes, we reached a significant reduction in our Algerian contracts. This has allowed us not only to avoid further take-or-pay, but even to recover 3.5 billion cubic meters of make-up gas. Moving to optimization and trading, our relatively new activities here in London have delivered robust growth last year.
2013 was also a good year for LNG, both for the diversion and delivery of 3 billion cubic meters from our portfolio, premium Far East markets, and also for the beginning of our effort to market the gas from Mozambique. As a result of all of this, adding back what we expect to recover from arbitrations for 2013, our overall performance last year was in line with guidance, notwithstanding a significantly worse scenario. Let's look at the market context in more detail. First of all, gas consumption in Europe is back to the level of the late '90s. We now expect that total demand will remain under 500 BCM by 2017. This is still 10% below 2008 and 20% below what we had previously foreseen. This year, we expect gas demand to remain flat. Moving to prices, long-term contracts in Europe still have to be aligned with the hubs.
In the meantime, the roles of the hubs is becoming more and more significant. This process is irreversible. The power sector clean spark spread has become negative in Europe and in Italy because of lower demand or competition from cheaper coal and from subsidized renewables. Any of these adverse market changes are more structural than cyclical. 2014, we will suffer a decline in the profitability of our B2B sales activity and in our power business. In total, this year, adjusting for the arbitration with Statoil, expect to offset the more negative scenario and close broadly in line with 2013. In this market context, we built a robust turnaround plan based on three pillars. First is the opening of a new round of negotiations with our suppliers. Second is to grow our high value-added commercial segments, the third is a profound restructuring of our operations and logistics costs.
Let's go through these one by one. Starting with our supply contracts. Our target is to buy gas at a price that allows us to make a reasonable margin in each market. Considering the recent fall in gas prices in Italy and the periodic price reviews that are backward-looking for a period of two to three years, the successful negotiations of 2013 are not enough to close the gap between our contracts and the markets. Put this into perspective. Had we not achieved the EUR 1.4 billion savings, today we would be paying 15% above the hubs. Even after the cuts, we are still paying an average price, which is higher than the hubs. We've already started seeking further significant discounts in almost all our supply contracts. These new rounds of discussions will close in 2014, 2015.
Given the progress we are making in these discussions and the strength of our contractual position, we can confirm today last year's target, which was to fully align our portfolio with the market by January 2016. In essence, we're only asking our suppliers for a fair application of the contracts. In one way or another, all these contracts are structured in a way to allow Eni to make money selling gas economically in the relevant markets. The stakes are significant. The negotiation process is complex, requires time. Sometimes, like in the case of Statoil, also requires third-party intervention. Finally, we're also working to revise our volume and off-take obligations in light of the lower demand. The second pillar of our turnaround is to grow our four high value-added business commercial business segment.
In LNG, our growth in the plan period will be driven by selling more of our portfolio into Asia. In the longer term, thanks to Mozambique, Eni will become one of the top LNG players, more than doubling current volumes. In optimization and trading, we conduct very low-risk, asset-based activities, leveraging the size and uniqueness of Eni's portfolio of contracts, transport capacities around Europe. Leveraging a well-developed trading platform also enhances our commercial capabilities. The traditional B2B market as we knew it does not exist anymore. Customers now want new price indices, flexible risk management solutions, and are no longer happy with the simple commodity delivery. Finally, other growth area with good commercial value remains the retail market. Overall, in gas, we aim to preserve our leadership role in Europe. Let's turn to the final pillar of the plan, which is our cost-cutting.
At the end of our plan, we target annual savings of over EUR 300 million per year. We will achieve this by integrating our foreign subsidiaries into Eni, therefore cutting unnecessary corporate costs. Second, we will be merging five separate operating centers into one single platform to centrally manage all our billing, our back office, and our other IT-based operations, cutting significant fixed operating expenditure. Finally, we're working to get rid of some of our capacity obligations that are no longer necessary as we sell less gas into the Italian market. This would have an effect of reducing our annual logistics costs. Adding all this up, we're confident that we will generate sustainable long-term profits in this business starting from 2015.
Once we complete the right-sizing of our cost base and have brought supply contracts in line with the markets, we expect to generate around EUR 1.2 billion of EBITDA by 2017. We also have a potential upside to this number in case the market tightens and the margins improve, which would bring us back to last year's targets in last year's scenario. Moving to Refining. Also here, we're applying an aggressive restructuring program to deal with the conservative outlook in Europe and in Italy. We're working together with R&M along three lines. Most important is cutting refining capacity. We have seen an overall 12% reduction in Italy in the last three years with the shutdown of four plants. In this context, Eni has contributed by downsizing Venice and Gela, cutting our own capacity by 13%.
The next three years, we plan a further reduction of 22%, bringing our total reduction to over one-third since 2012. Second, we're continuing with our efficiency program to reduce fixed costs and energy costs by a further EUR 140 million. Finally, we are now running our refineries in very close coordination with our traders here in London in order to constantly optimize the slates and capture market opportunities whenever they arise. Overall, capacity reductions, cost-cutting, and asset optimization will contribute EUR 600 million to the overall Refining and Marketing EBIT target. Thank you very much for your attention. I will now hand over to Massimo.
Thank you very much, Marco. Good afternoon, ladies and gentlemen. As mentioned in our presentation so far, last quarter, as well as the entire 2013, had been a tough time for Eni. Fourth quarter adjusted operating profit was down 29% versus 2012, suffering from the exploration and production drop of EUR 1.5 billion due to the extraordinary disruptions in Libya and Forex effects, which together accounted for two-thirds of the overall amount. Gas and Power benefited from the renegotiation with Gazprom, which more than compensated the effects of a worsening scenario. Refining and Marketing reported a loss of around EUR 100 million. Clearly affected by the near zero refining margin that prevail over the benefits of our turnaround actions. Fourth quarter adjusted net profits was down EUR 1.3 billion, down 14% versus 2012, while the full year dropped by 35%.
Our 2013 reported net profit recorded an increase of 24%, thanks to the realized disposals that also contributed in keeping the net debt flat comfortably within our leverage ceiling of 0.3. This remarkable financial result was achieved thanks to the robust cash contribution from the E&P, the material improvement in our midstream/downstream businesses, and CapEx discipline. E&P. Notwithstanding the well-known issue in production, causing a negative impact of EUR 1 billion, upstream confirmed its high-quality cash flow, recording a net contribution per barrel of $30 in line with 2012, in spite of scenario and inflation effects. In our mid/downstream businesses, we were able to enhance our cash balance by EUR 2 billion thanks to the improvement in working capital, the gas contract renegotiations, and the operating efficiencies achieved. At the same time, capital expenditure were kept essentially flat in compliance with our policy since 2008.
Turning now to our plan. Cash generation growth remains the cornerstone of our strategy. In 2014-2015 period, our cash from operations will recover quickly to reach a yearly average of around EUR 15 billion. The expected 40% increase versus 2013 will be underpinned by an improvement in all our businesses, and in particular, by the gas contract renegotiations and the recovery production. In the same two years period, we forecast to cash in an average of more than EUR 3 billion per year from disposals. It is worth mentioning that this amount includes the Russian licenses already cashed in last month. In 2016-2017, cash flow operations will grow further up to 55%, thanks to the additional step-up in production and the turnaround completion in other businesses, the contribution of which will more than absorb the effect of our underlying declining scenario.
As a consequence, the CapEx coverage from cash flow from operation will grow up to 114% in 2014-2015, and to 126% in 2016-2017. Assuming a flat Brent scenario, CapEx coverage in 2016-2017 will increase to almost 140%, while average free cash flow along the period of the plan is expected to grow by 45% versus 2013. Now, let me explain why we are confident in keeping constant CapEx profiles. Firstly, our past track record. As mentioned before, we held CapEx under strict control since 2008. That was our year of peak expenditure. Secondly, the robustness of our plan. Around two-thirds of our CapEx is already committed, which means we have high certainty on cost as negotiated in contract already in place. These elements, together with the conventional nature of our projects, that Claudio remembered a few minutes ago, give us even greater confidence about our projections.
Over the next four years, we will invest overall EUR 54 billion to deliver the growth highlighted today. This means a yearly average in line with past years, and a reduction versus the previous plan of over 5% achieved in E&P. More still, we will continue to boost our cash through a material disposal program aimed at rebalancing our presence in core areas, complex projects, and managing risk. Since 2012, we have completed a very substantial disposal plan, selling EUR 13 billion of assets and cashing back EUR 12 billion of debts. For the future, including the sale of Russian assets, we are targeting an additional EUR 9 billion of divestments, among which some exploration farm-do wn, and the remaining stakes in Snam and GALP. Overall, what we have done so far and envisage in the plan will result in a total cash-in of EUR 34 billion.
Our balance sheet will be stronger and more focused on high-return sectors. Our average capital employed is expected to remain flat at around EUR 77 billion, with some changes in its composition. E&P, that has already increased its weight by 13% in the past five years, is expected to grow further by 2017, while the other businesses decrease or remain steady. Among upstream geographical areas, we will expand our presence in Far East and Sub-Saharan Africa, supporting our diversification, as well reducing our exposure to North Africa. Unproductive capital being still in investment phase will decrease from 25% in 2013 to 15% in 2017, thanks to the pipeline of startups.
Over the plan, we will continue to announce our leverage position, which will be kept well within our maximum target of 30%. Finally, we are committed to keeping strong level of cash equivalents, tied to potentially maintain two years of independence from the financial markets. I'll let you over to Paolo.
Very good. We will face continuing headwinds in all our markets. We have therefore set out our 2014-2017 plan based on prudent, cautious, and conservative assumptions. In this challenging market environment, we will deliver a strong performance in all our businesses over the next four years. In Eni, we have built a very powerful engine. In 2017, 70% of our production will come from assets which are already producing today, and a further 15% from new fields which are on track to start up in the next 24 months. Our industry-leading exploration success provides attractive low-cost growth options, which will be partially monetized through disposals. With regard to our midstream and downstream businesses, we are executing a focused turnaround strategy. We've already cut the cash burn from these businesses from EUR 2.5 billion in 2012 to EUR 500 million last year.
Thanks to our actions, we target EUR 1.5 billion of operational cash flow in 2017. With CapEx past its peak, the net result of all this will be an attractive free cash flow profile, which will underpin a strong financial position and a progressive shareholder distribution policy. As you know, our shareholder distribution policy comprises dividends and share buybacks. The dividend per share is expected to grow over time at a rate which broadly reflects the group's underlying earning and cash flow growth, while taking into account investment requirements and the overall financial structure. The share buyback program is pursued at management's judgment when a number of conditions are met. With regards to our 2014 dividend, I will propose to my board a payment of EUR 1.12 a share, an increase of 1.8% on 2013.
For the buyback, when reviewing the numbers of our plan, I feel comfortable with the current program. Ladies and gentlemen, thank you for your attention. We would be delighted to answer your questions.
Good afternoon, gentlemen. We are ready now to start with the Q&A session. We will first collect questions from the floor, and then we will reply to a few questions by phone. Please, before asking, stand up and state your name. Thank you. Let's start.
Hi, it's Michele Della Vigna from Goldman Sachs. I have one question for Marco and one for Claudio. For Marco, in 2013, you showed the adjusted EBIT for the gas and power division, but could you just walk us through how you get to the underlying number there? In that, I thought that with the renegotiation with Gazprom action, you had a benefit that goes back quite a few years in 2013. Here it looks like we still have more to reclaim. For Claudio, I was just wondering if you could give us an update on Libya and where you currently stand in terms of production. Thank you.
Thank you, Michele. That chart is intentionally qualitative to say that we have taken out the 2012 proceeds from solution of one of the contracts. We have tried to give you what we consider apples to apples, because remember last year we said we were targeting to have in 2013, assuming we close everything, same underlying result as the previous year. The previous year had a EUR 500 million one-off. The underlying of 2012 was minus. What we've done is taken a prudent estimate of what we think we will recover in the future and added that back to.
For Libya, as you know, we had a very prudent approach, and we consider same production 2013 for 2014. We are still in a transition phase, so we have up and down. A few days ago, we reached 250,000 barrel per day. That is very nice production. Yesterday, Wafa has been shut down, so we lost 100,000 barrel per day. We are always in a transition phase. We think that is not just a geopolitical issue now, but after two years of closing, open our wells, we need also a special maintenance. For that reason, we hope to be able to have a 220,000 barrel per day as an average for 2014.
Thank you. Roberto Ranieri from Banca Intesa Sanpaolo. Two questions on the E&P, one question on the gas and power. I understand that your strategy is to go towards the cash flow production, probably more than production increase. 3% is a bit lower than last year plan, but you're enhancing your cash flow. My question is about your portfolio, specifically. In detail, in your chart, you indicated the breakeven price for ultra-deep water, which is $50, $55 a barrel. Basically, my question is, do you think that In another chart, you indicated also that this ultra-deep offshore production is strongly increasing for 2017 to 2023. My question is, if you see some risk of cash flow generation from these kinds of projects. Do you see any risk of, not for the breakeven, but you risk on margins and squeeze your return on the ultra-deep water?
Another question on the gas and power. Okay. The rationalization of the renegotiation of contracts means that you are renegotiating your contracts, the contracts you have currently, or you are just also changing your portfolio on this contract? One more question is, do you see in the next few years some risks of a squeezing of the trading margins for the LNG gas supply from the U.S.? One very last question is on chemicals restructuring. Could you please give us some indication on extra cost on chemicals restructuring plan? Thank you very much.
Yeah. I start with the E&P. I think that our presentation showed that our strategy has been, in the last six, seven years, to add a conventional asset. Our average breakeven price for the future project is $45 per barrel. We have most of our projects that are between $30, $40 per barrel, and we have 20% of our, we can say, more costly projects, LNG and deep offshore, that are about $56 per barrel. The average is $45, we don't have any risky projects. We have just conventional projects. I don't see any risk because the margin is quite high because we are about $45. We don't have any unconventional assets. We are just conventional assets and just marginal exposure on costly projects.
I think that the future is like now, with a very interesting cash flow generation. As I said, at the same price condition, our target is to increase in three-year plan our free cash flow of 9%. That is our main target.
Thank you. Regarding our plan, we do not assume any change in the portfolio, all our targets are based on the existing length of gas and duration of the contracts. However, in parallel with the price discussions, we are entertaining some considerations aimed at maybe reducing some of the enter into this new business phase, where the contracts will be more or less aligned with the markets, and let's say the old friends that one was able to extract from these contracts is no longer there. I wouldn't be surprised if, going forward, we see some volume reduction, but the targets you're seeing today are based on the existing. In terms of LNG, certainly the U.S. will come to market with volumes.
We're not seeing that pressure right now, market, nor in the medium term, nor in the longer term, are people who are out there selling the gas. I mean, that pressure point yet reflected in.
In chemicals, let's say all the numbers of the restructure are included in our numbers.
Thank you. Afternoon. Stephen Joseph Linden from Nomura. A number of questions. Just first on Nigeria, could you just clarify where production levels were last year? Going forward with reduced levels of production in Libya, just any guidance on tax? Just a tax rate at the group level, please.
Okay.
Just a question on the Congo. Could you talk about early production? I think there's a couple of projects you've put in the appendix on gas, but also I was surprised that your peak production in the outer years, I think you're suggesting 25,000 barrels per day from the Congo. I just wanted to get a clarification on how big you think production from Nené could be. That's it.
Congo. Nigeria is quite stable in general production now. We are producing about 120,000 barrel per day. This is our equity production. We are experiencing, like last year, issue on bunkering and sabotage. That is continued, because our potential production in Nigeria is 180,000 barrel per day. We are losing, against our potential, 60,000 barrel per day. We consider, as for Libya, the same assumption, that we don't have any improvement this year. It's quite flat. For Congo, when I talk about 5,000 barrel per day, was the test of the well. That is the potential for each well. We are going to, as I said before, that is a joint project, and we are going to phase. We start with the early production for the two fields we have, Nené and Litchendjili in 2015, and the second phase in 2016.
We continue until 2019, at the moment, with what we have found now, with the development that will be to a platform, because we are in shallow water, in equity production that could range between 70,000 and 80,000 barrel per day.
In terms of tax rate, we accounted for a 66% tax rate adjusted in 2013, and we consider it a sort of ceiling, because our expectation looking forward is to keep the same level as far as 2014. In part, we expect the tax rate starting to decline as, first of all, E&P will enjoy a lower tax rate because we'll start our production in countries in which tax rate is lower than the current average. Second, because of the recovery of our Italian businesses that will benefit a lower tax rate.
And
Hi, yes. Jon Rigby from UBS. Two questions. The first is on E&P. I think when you've spoken before, Claudio, I've been impressed by your focus on trying to bring projects from discovery to first production quickly to make sure you're monetizing your investment plans. If I look through the portfolio and judge it against when you first discussed those projects, I'm thinking about Block 15/06, Goliat, Perla, the MLE and Kashagan, there does seem to have been some delays around where your first aspirations were on those, and it does seem to keep cropping up. I just wonder whether there's an issue there that you're finding and whether you want to address them. The second is for Marco. I was just reading on your slide where you're using italics, "My contract should enable the buyer to market economically the gas delivered." I wondered whose quote that is.
Is that yours or is that from contract? I guess that wording is incredibly important in negotiations. Thanks.
The first on E&P. You talk about MLE and Kashagan. It's true. MLE and Kashagan were ready to start last year in 2012. Because of an MENA issue, we delayed over at least five, six months because we couldn't send our people on the ground. That was the main reason of the delay in MLE and Kashagan. After that, we reach our target production, which is about 250 million standard cubic feet per day. For Angola, as we presented last year, we had an issue in our contract for local content. We had a discussion one year for the project, and that was the reason why we shifted over eight months in Angola. It's not so big delay.
On our Perla, there is no delay because it has been always considered the end 2013, beginning 2015, and now we are confirming first quarter 2015. There is no delay in Perla. Goliat, there is a delay of four months because we are supposed to start in July, August, and now we talk about the end of the year. We are talking about marginal delays of some months. For some project because of geopolitical issue, for other because of technical, but it's not two or three years. I think that we don't see any problem in the future.
If I may add a comment. Every time we are not operator, we see much longer delays than ours.
Jon, thank you for your question. We couldn't put any specific contract wording in there, what we tried to do was put general concept that is, though, common to all contracts, and I think this is a hugely important point for us as we think about the sustainability. None of these contracts has anything in it that could force buyer, in this case us, to making a loss. There's never any FID associated with any of these contracts, never the concept of a loss. There was always a concept of sharing in a profit. I think this is very much reflected in the outcomes of the arbitrations that we have seen in other situations where very hard for the arbitrator, given these contracts to force one of the players in. Concept is a general
Hi, Angelo
Peter Hutton from RBC. A couple of the targets that you've got in E&P. You've got a cash flow generation target of 9% CAGR, which is at a flat $108, and you've got a volume target of 3% CAGR when the price goes down from where we are today to $90. Which is the base case, and what is the CAGR in cash flow if you take the same macro assumption as you're using for your production volume? Second question is on, that you've got 70% of your production from effectively the conventional, relatively mature fields coming through, which is where we've also seen some increases in cost inflation in OpEx as you try to reduce the depletion. Can you make a comment on the cost trends on that 70%, which constitutes quite a high level of base as well, please?
70% is existing production. What is already in production now, 70%. The rest is complement, is our new project. The OpEx are increasing. You saw this year that is a $1 increase because we are looking at the unit costs, and we had this backup production in Libya and Nigeria. That is about $110,000 per day. For that reason, the unit cost OpEx is being increased this year because it's just a matter of less production at the same level of cost. In the future, we will remain steady about $8.5 per barrel operating cost, due to the new, more expensive production, for example, from Kashagan or from Goliat, or from some Angola production because of the leased FPSO. That is operating cost, not CapEx. That is the main reason.
I think that if you look at the absolute value of OpEx, there is no big increase in our cost.
Giuseppe Bassi, Fidentiis Equities. I've got three questions. The first, again, on the targets of E&P. What is the target CAGR of production in case of Brent flat at the current price instead of decreasing to $90? Second question is on your E&P cash flow. If you can give us a sensitivity of what the cash flow becomes if, let's say, the Brent goes down to $70. The third question on your disposal plan. You quote EUR 3 billion disposal in corporate and others. Could you please give us some more colors about the areas where you think to be able to dispose of EUR 3 billion worth assets? Thank you.
Answer to the first question. At $90 per barrel, in 2017 instead of a $110 per barrels, we have a reduction of our CapEx from 3% to 2.5%. It's not very sensitive. At this level, with this kind of contract, it's not very sensitive to the oil price. $70 is very far away. It's a different world, in the sense that this is not a linear equation. Let's say we consider EUR 130 million for every USD in terms of net profit. Of course, this is if you move from 104 to 103. If you move from 104 to 70, that's another world. Frankly, I don't have a quick answer to that. What I can tell you is that since we have a breakeven at $45 for the new project, 70, we will still be profitable even at $70. As for disposals.
As for disposal, the number relates mainly to the shares of Snam and [GOS] that has been issued in 2012 and 2013, for which we have the right to repay the bondholders the shares.
Good afternoon, Alessandro Scauri from Mediobanca. I have a couple of questions. First of all, on cash flow, could you please give us the underlying assumption of the Forex that you have in your cash flow assumption that you have detailed? If it's 1.30, 1.35, or whatever. Second question on cash again, you said that 2014 production should benefit from a small contribution from Kashagan. Could you quantify what is this contribution? The third question for Mr. Scaroni. The buyback program in the slide 45, where you said that there is a multi-year buyback program. Is it possible to give us a range of this multi-year buyback program? Possible it is a three year, four year, five years, or the historical average that we saw in the past. Thank you.
In term of Forex, the assumption is 1.3 all along the four-year plan. Let me say that because of the cash in and cash outs we expect along the four years, cash in from operation and cash out from OpEx, even if we assume to change this kind of assumption, the overall result should remain more or less the same.
I think I made quite clear that when I read the numbers of our plan, all the numbers of our plan, on the assumption of our plans, oil price, the exchange rate with the dollar, et cetera, et cetera, I feel comfortable to continue to propose to my board, because by the way, this is a board decision, to continue share buyback. We are quite reluctant to give numbers because we give a posteriori numbers. We give the numbers when we have done it, because we want to keep a real flexibility on this program of buyback.
Cash again.
We consider a few thousand EUR. Few thousand [dollar] per nation, and thousand [dollar].
That's all.
Thank you. It is Lydia Rainforth from Barclays here. Could you just talk about, in 2017, where you see return on capital being, and whether that is something that you would look to target at that point? Just secondly, could you do an update on the Algerian operations for us?
Algeria what? Algeria, yes. Algeria operations.
The overall return on capital in 2017, if I well understood the question, would be in the range of 7.58%, assuming the decline in Brent scenario we announced as the base in our plan.
Algerian operations, you know that we are continuing the build-up of MLE. We have to drill some four, five wells this year, to reach a installed production of 280 million, roughly. We are developing also the Kashagan gas that started [too well] last year, and has to be developed, jointly with MLE. Then we have the MLE Kashagan oil that will be put into production in 2017. That are the activities on Algeria.
Hi, Oswald Clint from Sanford C. Bernstein. Another question on gas and power, Marco. You've been increasing your spot sales in the Italian market quite a bit. Give us a sense of how big that market is. Can you increase sales into the spot market? Just to clarify the Algerian gas volumes, you're not taking them at the moment into Italy. How much longer can you spare Algerian volumes coming into play? Is that something extended further? For Claudio, a question on Congo. I've heard you before talk about the Motema Beach reservoir being fantastic and beautiful. How does this new significant discovery look in Congo? I know you've flow tested part of it, but as you look across this reservoir, do you think it's going to be high quality or quite variable?
Thank you. The Algerian agreement lasts until the end of this year, till October 2014. It doesn't involve zero volumes, it involves a significant reduction in volumes in Italy, volumes that have been That will last for months. PSV, you're right, we have been active in the PSV, are ready to be a significant hub in Europe to the level of other European hubs. Not as liquid as the NBP hub, but certainly as liquid as French hubs are. I would consider our sales activity on part of our normal operation.
Congo is really a fantastic discovery, because it came after 70 years that in this area, in this block, Eni Congo haven't found anything. The result in Congo, we discovered just
Small reservoir, completely different to the Angola size. It's a huge discovery. We think that we are just at the beginning. The reservoir is not so good like in Mozambique, but the oil is very good. It ranges between 36 and 38 degree API, it's very good quality and low viscosity. I think that we can really find additional satisfaction in the area, because there are other three structures that we have to explore, and other appraisal wells. I think that we are just at the very beginning, but a wonderful-
Hi, Lucian Reid from Bank of Montreal. Claudio, a couple of questions about Mozambique, if I could. You drilled a well in the south of the block, you came out with a gas condensate discovery. I think you're looking for black oil there. Have you written off the potential for conventional oil down there, or is there still a play which is worth chasing? Secondly, maybe you can just update us on the status of the project in terms of utilization and gas sales, et cetera.
You saw during the presentation, I talked about Mozambique as a gas basin, we found so much gas that would be difficult to find oil to compensate for all this gas. In the south is true. The first well in the lower part found some wet gas, so completely different from the gas that we have found, very dry until now. We are going to drill a second well, an exploratory well this year. Our expectation is to find wet gas or condensate. That is very good because we can sell condensate. Always a hope to find oil, it's more a gas product. In term of project, as I said before, we increased the potential because since the last year, we discovered more additional 25 this year.
For the Block 4, we increased the number of LNG train, to create more flexibility, we move also offshore, that is just a part of the project. We didn't mention anything about GTL. That is another part of the project, it's still premature. For the rest, we are very close to issue tenders for the feed for the floating LNG. For the floating LNG in Coral reservoir, that is entire in Area 4, we think that we will be ready to take an FID before the end of the year for the floating LNG. That, for the market, say something.
We signed a number of confidentiality agreements. As I said, we are in the market for the early trains. We aim to have binding contracts in place before the end of the year to support Claudio's FID process. As I commented before, we're finding very strong interest and very strong demand for these early volume. Market, of course, Asia is the main reference market.
Hi there. It's Jason Kenney from Santander, and thank you for your presentation today. You've had great success with resource additions over the last few years, and I think that statistic of 2.5 times discoveries. How sustainable is this forward-looking five-year process? Have you got access to basins? Is there an internal target that's maybe a bit more tempered as to certain amount of resources planned on going forward? I'm conscious here that because you have found so much resource, are you going to go into a development mode, maybe one which limits the width of your value, but might come off the gas a bit? Should we be expecting that?
As I said during the presentation, we started two years ago to renew completely our portfolio on new basins, and we moved to the Pacific basin. We have two different priority, and we start two years ago. We have new fresh basin and new fresh target, exploration target in the Pacific area, in Norway, in Russian Barents Sea. We have also start revisiting our existing asset. When I talk about existing asset, I mean a known basin like Congo. Congo is a good example. We start two years ago to make a new study on the pre-salt, and we had the discovery, as we did in the Block 15/06. Remember that Block 15/06 was a relinquishment that we got, we studied, and we found more than 700 million barrel of oil, and then the same in Indonesia.
We are moving, as we did in the last six years, in these two directions. New basin, and we already reloaded that, and existing asset. We have on our new
That package, we have 10 billion barrels of risk equity, prospective resources, on which we are going to work in the next years. The target are less than one billion per year, that is a lot, is 800 million. It's not 2 billion or 1.8 billion like in the last years, because I don't think that is sustainable. It's still a very interesting and important target. As you said, we are going to have a lot of resources, and part of these resources will be developed, but part of these resources will be farmed out to anticipate the cash-in. Because it's oil, we have found good resources in easy projects, so low risk, and that is very interesting option that we already started using, and we're going to use again.
Thank you. It's Irene Himona, Societe Generale. I had two questions, please. One on Saipem and one on Kashagan. Saipem, they had a bit of a worse year than we all thought, I guess, and Eni has always managed that relationship at arm's length. I guess my question is, has anything changed as a result of the past few months, in terms of that relationship, and are you doing anything different? Secondly, on Kashagan, accidents happen. My question is there any provision in the contract as to what happens next? Obviously you're missing substantial cash flows and so is the government. Do we know once it's fixed and up and running, what follows? Is anything or is it force majeure?
Let me comment on Saipem. The relationship at arm's length with Saipem dates back to the time when Saipem was 100% of Eni, was working essentially for Eni, and at that time, it was, I believe, '97 or '96, it was decided that Saipem would be listed and to be managed at arm's length in order to gain new customers. As a matter of fact, Eni is not anymore the number 1 customer, not even the number 3 or number 4 customer since many, many years. Let's say the relationship at arm's length is the key to the success of the company itself. This does not mean that when we decide about our board representative, the management, et cetera, which we have a say as a shareholder, we have to choose the best people, make sure that the company is well managed.
We cannot interfere to their day-to-day activity, otherwise Saipem will lose customers. For Kashagan, there's no provision in the contract for problem or for cash flow that we are missing because of technical issue, which that there is any gross negligence. The only provision that we have in this contract, coming from the agreement in 2008, that we are not able to reach the KCP by the 1st of October. All the costs incurred after this date to reach the KCP are not recoverable. That doesn't mean that they're not recoverable from an insurance point of view. They are two different. If I may add something to this question about exploration, I wanted to give you a precise number.
You've seen before in that slide that we've discovered 2.5 times our productions, while all our peer group had discovered between 0.5 and 0.2 of their production in the same. If we exclude Mozambique, suppose we have not discovered Mozambique, which I rate as something somewhat exceptional. We cannot discover Mozambique very often. It's the biggest discovery of our history. We still would have discovered in the last five years, 1.2 times our production. Which means that, how can I say, systematically, we perform pretty well in exploration, and we can feed our resource base organically, which we believe to be the key of our profession, really the key of our profession.
For example, I don't know if you made this calculation, if we consider oil in place in we call Marine XII, so Litchendjili and Nené, and the fact that we have said 65% and a recovery rate normal, only Marine XII is almost one year of our production for us. Make the calculation. It's almost one year of our production. That is with one discovery, the one we announced today, we have fed our production, of course, it will take years, but with one year of production.
Thank you. It's Mark Bloomfield from Deutsche Bank. Two questions on targets, please. First of all, on your upstream volume target, I think you previously talked about a degree of headroom built into that number. Perhaps you can give us a sense of what kind of contingency is built into that target now. Secondly, in terms of your cash generation, perhaps you can give a sense of whether there's any working capital release built into your operating cash flow targets, either over the 2014/2015 or the 2016/2017 period, and particularly pertaining to the prepayments, which are built up in the gas and power division. Thanks.
Contingency now, we put some huge contingency in the first two years because of the geopolitical issue. For that reason, we said that if there is any geopolitical disruption, some impactful like last year, we can increase. We have been prudent, and we are in a range of 100,000 barrels per day on contingent. That is the range. We moved from the end last year. Last year, we had our contingency at the end period. Now we move at the beginning of the period because of geopolitical, and mainly because of Libya and Nigeria.
Expect in terms of addition to our cash flow from working capital in the next, I would say two years, we expect a slightly positive increase, slightly positive contribution.
Kristina Piskaryova from Standard & Poor's. I have two small questions. One is, has the problems in Venezuela impacted your project? The second one, I know it has been asked before, but I just want to find out if you haven't changed your opinion. Would you consider spinning off your retail, and just more focus on the E&P? There'll be real synergies there.
Venezuela, the short answer would be no. Time being, we are watching closely what happens in Venezuela because I've read somewhere that in Caracas last night, turmoil. So far, so good. They start the production in Junín 5, which is a batch of steel, and Perla project right now, on time. Corocoro, which is our. Let's say, time being, Venezuela is moving right. As for the retail business, our position is somewhat the following. Yes, we realize that retail is a business certainly very different from most of our other business. Here is a business in which one side we sell gas and electricity, and gas and electricity retail, and we sell it normally at a premium as compared to the market non-retail.
Second, we are so big in retail because we have more than 10 million customers, that we certainly have the scale, developed, right people, right IT system, right commercial strategy. It's not a small business lost somewhere. I don't know how many retailers, energy, gas, and power sell at 10 million customers, but I don't believe very many. It is a real business which is producing good returns so far. For the time being, we are still looking at the situation but taking no decision.
Okay, I think that we can now take a few questions by phone. There is any question on the phone, please?
No questions from the phone.
No questions. If you have any further questions?
Thank you. It's Neill Morton from Investec. A couple of questions, please. Firstly, to Marco. Several years ago when Eni was faced with market share limits in Italy, you tried to expand across the rest of Europe. I was just intrigued as to how supply margins ex-Italy bear with those in Italy right now. Just secondly, a very simple question, I suppose, for Claudio. Post the sale of your Russian upstream gas assets, how does the oil versus natural gas production split vary over the four-year plan?
I think the Italian market has now, as we discussed previously, more or less aligned itself to the PSV, and the PSV itself has aligned itself to the other northern markets. What used to be a premium market has now become exactly in line with the others. In terms of supply margin, we've built our business now in a way that we separate our supply activities from our marketing activity. Have an internal transfer pricing, we no longer think of supply margins in countries, commercial margins. More or less, they're going to be the same across.
Oil versus gas. By the end of this period, at 57% oil. At a long term to you. Our share, sorry. Our share oil will go down to 48% because most of the big oil have a huge production, about 400,000 barrel per day. That is what
That's the last one. I thank you for your patience.
Thank you very much.
Thank you.