Paolo Scaroni - Chief Executive Officer, General Manager, Chief Operating Officer of Gas & Power Division and Director Claudio Descalzi - Chief Operating Officer of Exploration & Production Division Marco Alverà - Senior Executive Vice President of Trading Business Unit Massimo Mondazzi - Chief Financial Officer

Michele della Vigna - Goldman Sachs Group Inc., Research Division Roberto Ranieri - Banca IMI SpA, Research Division Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division Jon Rigby - UBS Investment Bank, Research Division Alejandro Demichelis - Exane BNP Paribas, Research Division Peter Hutton - RBC Capital Markets, LLC, Research Division Giuseppe Rebuzzini - Fidentiis Equities S.V.S.A., Research Division Andrea Scauri - Mediobanca Securities, Research Division Lydia Rainforth - Barclays Capital, Research Division Oswald Clint - Sanford C.

Bernstein & Co., LLC., Research Division Iain Reid Jason Kenney - Grupo Santander, Research Division Irene Himona - Societe Generale Cross Asset Research Mark A. Bloomfield - Deutsche Bank AG, Research Division Christine Tiscareno - S&P Capital IQ Equity Research Neill Morton - Investec Securities (UK), Research Division

Very good. Good afternoon, ladies and gentlemen, and welcome to our full year result and strategy presentation.

Most of you will have already seen our 2013 results this morning, but I would like to take this opportunity to 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, start-ups 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 4 main factors: First, the underlying strength of our E&P portfolio.

Thanks to our low-cost position, we continued to deliver an average cash flow per barrel of around $30; second, the ongoing turnaround in our mid-downstream businesses, which delivered 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; and 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 & 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, 2 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 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 2 years of the plan and up to 55% in the final 2 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 2.5x our production in the period.

And this success continues, as highlighted by the giant discovery in Congo, announced today. Thanks to the breadth of our portfolio, we will monetize some discoveries or even producing assets without affecting our longer-term growth prospects.

We've 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 Artic gas in Russia.

In spite of these asset sales and of prudent 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 with the 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 or rephasing of growth opportunities. Turning now to our mid-downstreams operations, we target 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 contracts, capacity cuts and operating optimizations; and secondly, focusing our presence on resilient markets. We target overall EBIT and cash breakeven in 2015.

And over the planned period, these businesses will generate an accumulated EUR 3 billion in operating cash. Let's look at each business in more detail.

In Gas & Power, our turnaround is based on 3 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 cost 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 of EBITDA by 2017.

Finally, the reengineering of the whole business, aligning it to new market conditions by streaming -- 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 these actions will be an increase of about EUR 600 million, EUR 700 million in EBIT, which will become positive in 2015. In Versalis, our Chemical business, we made excellent progress on each of the 3 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 and 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 closure of Hythe in the first quarter of 2014, so this quarter. 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 breakeven in 2016.

We will achieve cash flow breakeven in 2015. Our strategy will deliver significant improvement in operating cash flow, 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 2 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 Artic 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 Brent 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 distinct E&P model and our short- and long-term target. This model is the basis for our strategy to overcome industry challenges, in containing cost and generating free cash flow.

Before speaking about it, let's have a look at 2013. This year, we recorded our best performance in HSE, with a total recordable injury rate 60% lower than the previous 6 years and 0 blowout for the 10th consecutive year.

Our exploration performance continued to exceed expectation, with about 1.8 billion barrel of discovered resources at $1.2 per barrel. We achieved all the 8 planned major startups, and we took 7 main FIDs, adding 2P reserves for more than 1 billion barrel.

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 contest. Over the last few years, the upstream industry has faced 2 key issues; a strong increase in total expenditure and poor production growth.

Since 2008, the major expenditures had increased by about 40%. This was mainly due to big M&A transaction 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.

So what has made this different trend and result possible for Eni? This has been possible for 4 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 new discovery, through a phased approach to investment, which allow us to reduce upfront financial exposure also for giant projects; and 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 6 years, following the same approach, targeting conventional assets.

To do this, we have renewed our portfolio with 2 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 Artic, where we target oil in the Norwegian and Russian Barents Sea.

And the second priority's come through a major review of our legacy assets, where we apply a new geological play concept and leading proprietary technologies. We have already achieved an exciting result 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 barrel of resources in place. Through this discovery, we cracked the code of the pre-salt in Congo.

This achievement was the result of the deploying Eni-leading proprietary technologies to an asset which had already been explored since the '70s without revealing any discoveries. The block operated by Eni with 65% stake is in shallow water, only 17 kilometers from the shoreline and close to our existing offshore facilities.

The Nene 3 well has found very good-quality oil, and during the production test, the well delivered more than 5,000 barrel per day. In addition to the 2.5 billion barrel 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 this new discovery into production already in 2015. The renewed portfolio made up of new emerging asset and the revisited, the legacy ones, give us prospective resources of about 10 billion barrel, of which we are targeting 3.2 billion in the next 4 years at a very low cost of about $2.2 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% to 80%.

The Mozambique transaction is a result of this model. 80% of these huge exploration successes of the last 6 years will be developed in less than 7 years, the strong focus on time-to-market as a first key step, the timely sanctioning of our projects.

In the next 4 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 barrel of 2P reserves.

In the 4-year plan, we will put 26 major projects into production, more than half in the next 2 years, contributing about 500,000 barrel per day in 2017. These projects are geographically well-balanced, mainly through our Europe, Sub-Saharan Africa, East Asia and the Americas.

Here, you can see an update on how we are progressing on the main sanctioned project. All are on schedule, with only 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 UCAP and commissioning.

The result of this is a project portfolio where we have better control, reduced risks and contained costs. And 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 were onstream, 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, saving more than 3 months of shutdown and allowing, once the gas pipeline is restored, a faster ramp-up of production without further interruptions. Also, 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 sail away 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 4-year plan, Mozambique will pillar of our medium-term growth. We completed the exploration phase on Mamba Complex with 11 successful wells.

Potential straddling 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 1 appraisal well and 1 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 straddling resources in Area 4, where unitization has been agreed, Eni's planning 1 initial onshore LNG trains, plus 2 floating LNG units, with a total capacity of 10 million TPA and an option for a further onshore LNG train.

Eni's also ready to launch the development for 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 asset, with an average break-even price of $40 per barrel. Even deep and ultra-deep projects have a very robust economic, with an average break-even price of $55 per barrel.

Our project is very robust also in term of cash generation. Considering 2013 ramp-ups and the full year planned 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 asset 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 these crucial assets, our objectives are to fight depletion and prolong the life of our field, with an average target of 70,000 barrel per day from production optimization project, reduce facility downtime to less than 6%, increase the recovery factor with a target of 43% for oil and around 70% for gas.

Now, the plan's main objectives. In the next 4 years, we confirm a production average growth rate of 3%.

Our 2014 production is flat versus last year's, excluding the disposal -- disposed Russian production. This takes into account no improvement in Libya and Nigeria, and a marginal contribution from Kashagan.

Our performance could improve materially if geopolitical disruptions 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 projects in East and West Africa, the Americas and East Asia will sustain an annual growth rate of 4%. In the next 4 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 increasing cash generation. We expect to meet these cost targets for the following reasons: 60% 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. And second, we have low 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, an efficient project development and resilient producing assets. Second, over the years, thanks to CapEx discipline and operational efficiency, we have maintained on outstanding self-financing ratio above 100% and we intend to increase this to more than 140%.

Leveraging on these factors, over the planned period, we're in the right position to increase our cash flow from operation and our free cash flow by 9%. Thank you for your attention and I'll 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 & 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 contract. This has allowed us not only to avoid further take-or-pay, but even to recover 3.5 billion cubic meters of makeup 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 into 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 late '90s. We now expect that total demand will remain under 500 bcm, 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.

In the power sector, the clean spark spread has become negative in Europe and in Italy because of lower demand, more competition from cheaper coal and from subsidized renewables. Many of these adverse market changes are more structural than cyclical.

In 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, we 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 3 pillars: The first is the opening of a new round of negotiations with our suppliers; the second is to grow our high value-added commercial segments; and 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 2 to 3 years, the successful negotiations of 2013 are not enough to close the gap between our contracts and the markets.

To 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.

Therefore, we've already started seeking further significant discounts in almost all our supply contracts. These new rounds of discussions will close in 2014 and 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 to the market by January 2016. In essence, we're only asking our suppliers for a fair application of the contracts.

And 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 negotiations process is complex, requires time and 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 4 high value-added business commercial business segments. 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 exploiting the size and uniqueness of Eni's portfolio of contracts and 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, another 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 5 separate operating centers into 1 single platform to centrally manage all our billing, our back-office and our other IT-based operations, cutting significant fixed operating expenditure. And 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 rightsizing of our cost base and have brought supply contracts in line with the market, 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 3 lines. The most important is cutting refining capacity.

We have seen an overall 12% reduction in Italy in the last 3 years, with the shutdown of 4 plants. In this context, Eni has contributed by downsizing Venice and Gela, cutting our own capacity by 13%.

In the next 3 years, we plan a further reduction of 22%, bringing our total reduction to over 1/3 since 2012. Second, we're continuing with our efficiency program to reduce fixed costs and energy costs by a further EUR 140 million.

And finally, we are now running our refineries in very close coordination with our traders here in London in order to constantly optimize a slate and capture market opportunities whenever they arise. Overall, the 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 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 & Production drop of 1.5 billion due to the extraordinary disruptions in Libya and ForEx effects, which together, accounting for 2/3 of the overall amount.

Gas & Power benefited from the renegotiation with GasTerra, which more than compensated the effects of a worsened scenario. Refining and Marketing reported a loss of around EUR 100 million, severely affected by the near 0 Refining margin that prevailed over the benefits of our turnaround actions.

Fourth quarter adjusted net profit was down EUR 1.3 billion, down 14% versus 2012, while the full year dropped by 35%. However, 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 E&P, the material improvement in our mid, 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 announce 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, '15 period, our cash flow operations will recover quickly to reach a nearly 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 in production. In the same 2 years period, we forecast to cash in an average of more than EUR 3 billion per year from disposals.

It's worth mentioning that this amount includes the Russian licenses already cashed in last month. In 2016, '17, 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 underlining declining scenario.

As a consequence, the CapEx coverage from cash flow from operation will grow up to 114% in 2014, '15 and to 126% in '16, '17. Assuming a flat Brent scenario, CapEx coverage in '16, '17 will increase to almost 140%, while average free cash flow along the period of the plan is expected to grow by 45% versus 2013.

And now, let me explain why we are confident in keeping constant CapEx profile. 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 2/3 of our CapEx is already committed, which means that we have high certainty on cost as negotiated in contracts already in place.

This element, 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 4 years, we will invest overall EUR 54 billion to deliver the growth highlighted today.

This means a nearly average in line with past years and the 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 risks. Since 2012, we have completed a very substantial disposal plan, selling EUR 13 billion of assets and cashing back EUR 12 billion of debt.

For the future, including the sale of Russian assets, we are targeting an additional EUR 9 billion of divestments, among which, some exploration farm-down and the remaining stakes, 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's already increased its weight by 13% in the past 5 years, is expected to grow further by 2017, while the other businesses decrease or remain steady. Among the 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 start-ups. 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 sized to potentially maintain 2 years of independence from the financial markets. And now, I'll let you over to Paolo for the last remarks.

Very good. Summing up, 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 4 years.

In E&P, 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 regards to our mid and downstream businesses, we are executing a focused turnaround strategy.

We have already cut the cash burn from these businesses from EUR 2.5 billion in 2012 to EUR 500 million last year. And 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 proof sure that 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. As 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, ladies and 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.

It's Michele della Vigna, Goldman Sachs. I had one question for Marco and one for Claudio.

For Marco, in 2013, you showed the adjusted EBIT for the Gas & 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 GasTerra, actually, you had a benefit that goes back quite a few years in 2013.

But here, it looks like you still have more to reclaim. And for Claudio, I was just wondering if you could give us an update on Libya and where you currently stand in terms of production?

Okay. Thank you, Michele.

That chart is intentionally qualitative to say that we have taken out the 2012 proceeds from a 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, the same underlying result as the previous year.

Now, the previous year had a EUR 500 million one-off, and so the underlying of 2012 was minus kind of EUR 200 million. And so, what we've done is we've taken an estimate, a prudent estimate of what we think we will recover in the future and added that back to '13.

So for Libya, as you know, we have a very prudent approach, and we consider the same production in 2013 for 2014. We are still in a transition phase.

So we have up and down. A few days ago, we reached 250,000 barrels per day.

That is very nice, very nice production. But yesterday, Wafa has been shut down, so we lost 100,000 barrels per day.

So we are always in a transition phase. We think that is not just a geopolitical issue now, but after 2 years of close and open our wells, we need also a special maintenance.

So, for that reason, we hope to be able to have a 220,000 barrels per day as an average for 2014.

Roberto Ranieri from Banca IMI, São Paulo. Two questions on the E&P, and one question on the Gas & Power.

I understand that your strategy is to go towards cash flow production, probably more than the production increase. 3% is pretty lower than last-year plan, but you're enhancing your cash flow.

My question is about the -- your portfolio specifically. In detail, in your chart, you indicated a different price for ultra-deep water, which is USD 50, USD 55 per barrel.

So, basically, my question is do you think that -- and in another chart, you indicated also that this ultra-deep offshore production is strongly increasing towards 2017 and 2023. So my question is if you see some risk of cash flow generation from this kind of a project.

So do you see any risk of -- not for the breakeven, but your risk on margins and squeeze your returns on the ultra-deep water? Another question on the Gas & Power, okay, the rationalization of the -- renegotiation of contracts means that you are renegotiating your contracts or the contracts you have currently, or you are just also changing your portfolio from these contracts?

And one more question is, do you see in the next few years some risks of squeezing of the margins, 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?

Okay, I start with E&P. So I think that our presentation showed that our strategy has been, in the last 6, 7 years, to have conventional assets.

And our average break-even price for the future, for the project -- for the future project is $45 per barrel. So we have most of the -- of our project that are between $30 and $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.

So the average is $45. And we don't have any risky projects.

So we have just the conventional projects. So I don't see any risk because the margin is quite high, because we are about $45.

We don't have any unconventional asset. We are just conventional asset and just margin exposure on costly projects.

So I think that the future is like now, with a very interesting cash flow generation. As I said, at the same condition -- same price condition, our target is to increase in 4-year plan our free cash flow of 9%.

So that is our main target.

Thank you. Regarding our plan, we do not assume any change in the portfolio, so 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 volumes as we enter into this new business phase where the contracts will be more or less aligned with the markets and let's say the old rent that one was able to extract from these contracts is no longer there. So I wouldn't be surprised if, going forward, we see some volume reduction.

But the targets you have seen today are based on the existing volumes. In terms of LNG, certainly, the U.S.

will come to market with volumes. We're not seeing that pressure right now in the market, nor in the medium term, nor in the longer term.

Our people who are out there selling the gas from Mozambique are not finding that pressure point yet reflected in the pricing.

Restructuring costs? The cost of restructuring in the U.S.

Chemicals.

In Chemicals. Let's say all the numbers of the restructure are included in our numbers.

Theepan Jothilingam from Nomura. A number of questions.

Firstly, just -- first on Nigeria, could you just clarify where production levels were last year? And then, going forward with reduced levels of production in Libya, just any guidance on tax?

And then just a tax rate in -- at the group level, please? And then, just a question on the Congo.

Could you talk about sort of 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 sort of -- in the outer years, I think you're suggesting sort of 25,000 barrels per day from the Congo. So I just wanted to get a clarification on how big you think production from Nene could be?

That would be great.

So Nigeria and Congo. Nigeria is quite stable in terms of production now.

It's -- we are producing about 120,000 barrels per day. This is our equity production.

We are experiencing, like last year, issue on bankruptcy [ph] and sabotage, that is -- it's continuing because our potential production in Nigeria is 180,000 barrels per day. So we are losing against our potential 60,000 barrels per day, and we consider, as for Libya, the same assumption that we don't have any improvement this year.

So it's quite flat. For Congo, when I talk about 5,000 barrels per day, it was the test of the well.

So that is the potential for each well. And we are going to -- as I said before, that is a joint project and we are going to face.

So we start with the earlier production for the 2 fields that we have, Nene and Litchendjili in 2015 and a second phase in 2016, and then we continue until 2019 with a -- at the moment, with what we have found now, with the development that will be through a platform because we are in shallow water, an equity production that could range between 70,000 and 80,000 barrels per day.

So in terms of tax rate, we accounted for a 66% tax rate adjusted in 2013, and we consider it as sort of a ceiling because our expectation looking forward is to keep the same level as far as 2014 and start -- we expect the tax rate starting to decline as first of all, the E&P will enjoy a lower tax rate because we start up production in countries in which tax rate is lower than the current average; and second because of the recovery of our Italian businesses that will benefit a lower tax rate.

It's Jon Rigby from UBS. Two questions.

The first is on E&P. I think when you've spoken before, Claudio, is 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 fast.

But if I look through the portfolio and judge it against when you first discussed those projects, I'm thinking about Block 15/06, Goliat, perhaps Perla, the MLE and CAFC, there does seem to have been some delays around where your first aspirations were on those, and it does seem to keep cropping up. So 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 use in italics, "supply contracts shall enable the buyer to market economically the gas delivered."

I wondered whose quote that is. Is that yours, or is that from a contract?

Because I guess those -- that wording is incredibly important in terms of negotiations.

First on E&P. So, yes, you talk about MLE and CAFC gas.

So MLE and CAFC, we are ready to start last year, in 2012, and because of unanimous [ph] issue, we delayed of practically 5, 6 months because we couldn't send our people on the ground. So that was the reason, the main reason, of the delay in MLE and CAFC gas.

After that, we reach our target production. It is about 250 million standard cubic feet per day.

And so for Angola, as we presented last year, we had an issue in our contract, for our local content, so we had a discussion of 1 year for the project. And that was the reason why we shift of 8 months, Angola, so it's not so big a delay.

And on Perla, there is no delay because it's always -- has been always considered at the end 2013, beginning 2015, and now we are confirming first quarter 2015. So there is no delay in Perla.

Goliat, there is a delay of 4 months because we were supposed to start in August -- July, August, and now we talk about the end of the month -- the end of the year. So we are talking about marginal delays of some months for some project because of geopolitical issue; and for other, because of technical.

But it's not 2 or 3 years. So I think that we don't have -- we don't see any problem in the future, honestly.

Now, 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.

So what we tried to do is put a general concept that is, though, common to all contracts. I think this is a hugely important point for us as we think about the sustainability of this business.

None of these contracts has anything in it that could force the buyer, in this case us, to be making a loss. So there's never any FID associated with any of these contracts.

There's 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 it's very hard for the arbitrator, given these contracts, to force one of the players into a loss. So I think the concept is a general one.

Alejandro Demichelis from Exane BNP Paribas. Two questions.

The first one is on the lower CapEx that you're indicating now over the next period. Is that just a rephasing of the project, or do you see any kind of lower cost included in some of the projects?

And the second question is in terms of the restructurings you were talking about, all of the numbers -- just to confirm, all of the numbers for the new restructuring are included in the EUR 2.4 billion impairment that you took in the fourth quarter or is something more to come?

Oh no. Quick answers, rephasing, is the first answer to your question.

And second, are included.

Peter Hutton from RBC. Just 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 on what is the CAGR in cash flow if you take the same macro assumption as you're using for your production volume target?

5%.

Second question is on the -- you've got 7% -- I'm sorry, you've got 70% of your production from effectively, sort of, conventional, relatively mature fields coming through, which is where we were also seeing some increases and 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?

So the 70% is the existing production in -- so what is already in production now, 70%. The rest is -- the complement is our new projects.

So the OpEx are increasing. You saw this year that it's a $1 increase because we are looking at the unit cost and we had this lack of production in Libya and Nigeria.

So that -- so it's about 110,000 barrel per day. So for that reason, the unit cost OpEx has been increased this year because it's just a matter of less production at the same level of cost.

In the future, we have -- we are about -- we will remain steady about $8, $8.5 per barrel operating cost due to the new and more expensive production from -- example from Kashagan or from Goliat, or from some Angola production because of the leased FPSO; that is the operating cost not a CapEx. So that is the main reason.

But I think that if you look at the absolute value of OpEx, there is no big increase in our costs.

Giuseppe Rebuzzini, Fidentis Equities. I've got 3 questions.

The first again on the targets of E&P. What is the target CAGR of production in case of a 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 dollar -- the Brent goes down to $70?

And the third question on your disposal plan, you caught 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?

So I can answer to the first question. If we are $90 per barrel, so in 2017 instead of the $110 per barrels, we have a reduction of our CAGR from 3% to 2.5%.

So it's not very sensitive to -- at this level with this kind of a contract, it's not very sensitive to the oil price.

Let me give you now. $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 $1 in terms of net profit.

But, of course, this is if you move from $104 to $103. If you move from $104 to $70, that's another world.

And, frankly, I don't have a quick answer to that. What I can tell you is that since we have a cost, we have a breakeven at $45 for the new projects, so $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 Galp but they are linked to the convertible bonds that has been issued in 2012 and '13, and for which we have the right to repay the bondholders through the shares.

Andrea Scauri from Mediobanca. I have a couple of question on -- first of all, on cash flow.

Could you please give us the underlying assumption of ForEx that you have in your cash flow assumption that you have detailed, if it is a 1.30, 1.35, or whatever? Second question on Kashagan, you said that 2014 production should benefit from a small contribution from Kashagan.

Could you quantify what is this contribution? And a third question for Mr.

Scaroni. The buyback program in the Slide 45, you said that there is a multiyear buyback program.

Is it possible to give us a range of this multiyear buyback program if possible, if it is 3 year, 4 year, 5 years or historical average that we saw in the past?

You answer the first one.

So, yes, in terms of ForEx, the assumption is 1.3 all along the 4-year plan. But let me say that because of the cash in and cash outs we expect along the 4 years.

So cash in from operation and cash out from OpEx, even if we assume to change these kinds of assumption, the overall result should remain more or less the same.

Now, as for the share buyback program, 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, of course, so oil price, 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 a share buyback program. Now, we are quite reluctant to give numbers.

Of course, 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.

For Kashagan, we consider a few thousand barrel, a few thousand barrel per day, some thousand barrel per day.

Lydia Rainforth from Barclays. 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?

And then just secondly, could you do an update on the Algerian operations for us and what's going on there?

Nigerian what?

Algeria, sorry.

Algeria yes, Algeria operations, okay.

So the overall return on capital in 2017, if I well understood the question, would be in the range of 7.5%, 8%, assuming the decline in Brent scenario we announced as a base in our plan.

For Algerian operations, you know that we are continuing with the buildup of MLE and we have to drill some 5 wells this year to reach a potential production of about 280 million standard cubic feet per day. And we are developing also the CAFC gas that start with 2 wells last year and have to be developed and jointly with MLE.

And then, we have the MLE-CAFC oil that will be put in production in 2017. So that are the activities on Algeria.

Oswald Clint from Sanford Bernstein. Another question on Gas & Power, Marco.

You've been increasing your spot sales in the Italian market quite a bit. Could you give us a sense of how big that market is?

Can you keep increasing sales into spot market? And just to clarify the Algerian gas volumes.

You're not taking them at the moment into Italy, and how much longer can you defer Algerian volumes coming into Italy? Is that something that can be extended further?

And for Claudio, a question on Congo. I've heard you before talk about the Mozambique reservoir being fantastic and beautiful.

How does this new significant discovery look in Congo? I know you flow-tested a part of it.

But as you look across this reservoir, do you think it's going to be high-quality or potentially quite variable?

Thank you. So the Algerian agreement lasts until the end of this year, until October 2014.

And it doesn't involve 0 volumes. It involves a significant reduction in volumes in Italy and some volumes that have been moved from Italy to another market.

So that will last for the coming months. The PSV, you're right.

We have been active in the PSV. We consider the PSV already to be a significant hub in Europe to the level of other European's hub.

Not as liquid as the NBP or the TTF, but certainly as liquid as the French hubs are. So I would consider our sales activity on the PSV as part of our normal operations.

So Congo is really a fantastic discoveries because it came up after 70 years that in this area in this block, any company found anything. So the pre-salt in Congo, we discovered just small, small, small reservoir, so completely different to the Angola sites.

So it's a huge discovery. We think that we are just at the beginning.

The productivity so is -- the reservoir is not so good like in Mozambique, but the oil is very good. It's a Brent between 36 and 38, the degree API, so it's very good quality and low viscosity.

So I think that we can really find additional satisfaction in the area because there are other structures, other 3 structures that we have to explore, and other appraisal wells. So I think that we are just at the very beginning, but a wonderful beginning.

Iain 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 and you came out with a gas condensate discovery. And I think you're looking for black oil there.

Have you written off, though, potential for conventional oil down there or is there still a play which is worth chasing? And secondly, maybe you can just update us on the status of the project in terms of unitization and gas sales, et cetera?

No, the sales, I -- before, during the presentation, I talked about Mozambique as a gas basin because we found so much gas that it will be difficult to say oh, it's a condensate all this gas. So in the south it's 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.

So we are going to drill a second well, an exploratory well this year and our expectation is to find wet gas, so condensate. That is very good because we can sell condensate.

We don't think but there's always a hope to find oil, is more a gas province. Internal project, as I said before, we increased the potentiality because since last year, we discovered more additional 25 tcf.

So for the block 4, we increased the number of train, LNG train, and to create more flexibility, we move also offshore. And that is just a part of the project.

We didn't mention anything about GTL, that is another part of the project, but it's still premature. But for the rest, we are very close to issue tender for the feed, for the floating LNG and for the floating LNG in Coral reservoir that is entirely in Area 4.

We think that we will be ready to take an FID before the end of the year for the floating LNG. So that -- for the market, maybe you can say something, Marco.

So 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. And as I commented before, we're finding very strong interest and very strong demand for these early volumes in the market.

Of course, Asia is the main reference market at this point.

It's Jason Kenney from Santander. So you've had a great success with resource additions over the last few years, and I'm -- I think that statistic of 2.5x discoveries to production is truly remarkable.

How sustainable is this on a -- say, a forward-looking 5-year process? I mean, have you got the access to basins, the early access to basins to deliver that again, or is there an internal target that's maybe a bit more tempered, a bit more modest that you have to add a certain amount of resources per annum going forward.

And I'm conscious here that because you have found so much resource, you're now going to go into a development mode and maybe, well, exploration is the root of your value, the foot might come off the gas a bit and we shouldn't be expecting that kind of resource addition to come at us again, but maybe you can tell me?

As I said during the presentation, we are really -- we started 2 years ago to renew completely so our portfolio on new basins, and we moved to the Pacific basin. So we have 2 different -- as I said, 2 different priority.

And we start 2 years ago. So we add new fresh basin and new fresh target, exploration target in the Pacific area in Norway, in Russia, Bering Sea, and we have also start revisiting our existing assets.

And when I talked about existing asset, I mean it is a known basin like Congo. Congo is an example.

We start 2 years ago to make a new study on the pre-salt and we had the discovery as we did in the Block 1506. Remember that Block 1506 was a relinquishment that we got, we studied and we found more than 700 million barrel of oil, and then the same in Indonesia.

So we are moving, as we did in the last 6 years, in these 2 directions. New basin and we already reloaded that and existing asset.

And we have -- on our new package, we have 10 billion barrels of risk equity prospective resources that we are going to -- on which we are going to work in the next years. The target are less than 1 billion per year.

That is a lot. It's 800 million.

So it's not 2 billion or 1.8 billion like in the last years because I don't think that is sustainable. But it's still a very interesting important target.

And 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 from us to anticipate the cash in. So because it's oil, it's good, we have found good resources in easy project, so low-risk, and that is very interesting option that we already start using are we're going to use again.

Irene Himona from Société Générale. I had 2 questions please, one on Saipem and 1 on Kashagan.

Saipem, they had a bit of a worst year than we all thought I guess, and Eni has always managed that relationship at arm's length. And 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, is there any provision in the contract as to what happens next? So, obviously, you are missing substantial cash flows and so is the government.

Do we know once it's fixed and up and running, what follows if anything or is it force majeure?

Let me comment on Saipem. The relationship at arm's length with Saipem dates back at 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 should be listed and to be managed at arm's length in order to gain new customers. And as a matter of fact, Eni is not anymore the #1 customer, not even the #3 or #4 customer since many, many years.

So let's say the relationship at arm's length is the key to the success of the company. Now, then this does not mean that we have to -- when we decide about our board representative, the management, et cetera, in which we have a say as a shareholder, we have to choose the best people and to make sure that the company is well-managed.

But we cannot interfere into their activity, day-to-day activity, otherwise Saipem will lose the customers.

So for Kashagan, as you know, there is no provision in the contract for problem of a cash flow that we are missing because of technical issue, at least that there is any gross negligence. The only provision that we have in this contract, coming from the agreement 2008, that if you are not able to reach the KCP by 1 October, all the cost incurred after this date to reach the KCP are not recoverable.

That doesn't mean that they are not recoverable from an insurance point of view. So that are 2 different things, but there is no other kind of option in the contract.

If I may add something to this question about exploration, but I wanted to give you a precise number, no. If -- you've seen before in that slide that we have discovered 2.5x our productions, while all our peer group discovered between 0.5x and 0.2x of their production in the same period.

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 bigger discovery of our history, we still would have discovered in the last 5 years 1.2x 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, no, I don't if you made this calculation. But if we consider oil in place in what we call Marine 12, so Litchendjili and Nene, and the fact that we have 65% and a recovery rate normal, only Marine 12 is almost 1 year of our production for us.

Now, if you make the calculation, no, it's almost 1 year of our production. This is with 1 discovery, the 1 we announced today, we have fed our production.

Of course, it will take years, but with 1 year of production.

Mark Bloomfield from Deutsche Bank. Two questions on targets please.

First of all, on your upstream volume target, I think you've 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 target, so either over the '14, '15 or the '16, '17 period, and particularly pertaining to the prepayments which have built up in the Gas & Power division.

So contingency in our plan, we put some huge contingency in the first 2 years because of geopolitical issues. So for that reason we said that if there is any geopolitical disruption, so impacts like last year, we can increase.

So we have been prudent and we are in a range of 100,000-or-more barrel per day of contingency; that is the range. So we move from the end last year.

One -- last year, we had our contingency at the end of the period. Now, we move at the beginning of the period because of geopolitical and mainly because only in [ph] Nigeria.

Just back in term of contribution to our cash flow from working capital, in the next, I would say, 2 years, we expect a slightly positive increase, a slightly positive contribution.

Christine Tiscareno from Standard & Poor's. I just have 2 small questions.

One is, has the problems in Venezuela impacted your project? And 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 sector and becoming just more focused on the upstream? Do you still believe in the synergies there?

On Venezuela, the short answer would be no. No, for the time being.

We are watching closely what happens in Venezuela because I have read somewhere that in Caracas last night there has been some turmoil, but so far, so good in Venezuela. We have started production in Junin 5, it's a small production still, but we are moving ahead.

Perla project is on time, right, Claudio?

Yes, it's on time.

Is on time. Corocoro, which is our existing field, is producing according to plan.

So let's say, for the time being, Venezuela is moving in the right direction. As for the retail business, we -- our position is some of the following.

Yes, we realize that retail is a business certainly very different from most of our other businesses, still is a business in which on one side we sell gas and electricity and we have gas and electricity to sell. We sell it normally at a premium as compared to the market nonretail and B2B or wholesale.

And second, we are so big, so big in retail because we have more than 10 million customers, that we certainly have the scale to develop the right people, the right IT system, the right commercial strategy. So it's not a small business lost somewhere.

I don't know how many retailers of energy, gas and power in Europe sell at 10 million customers, but I don't believe very many. So it is a real big business, which is producing good returns so far.

So, for the time being, we are still looking at the situation, but taking no decisions.

I see that we can now take a few question by phone, if there is any question on the phone, please? So no questions.

If you have any further questions?

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'm just intrigued as to how supply margins x Italy compare with those in Italy right now?

And then 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 4-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. So 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 activities. So we have an internal transfer pricing.

So we no longer think of supply margins in countries but we have commercial margins. And more or less, they're going to be the same across Europe.

So, for the percentage of oil versus gas, so by the end of the period, we'll have 57% oil and the rest, 43%, gas. And if we look at the long-term period, 2023, our share -- sorry, our share oil will go down to 48% because Mozambique will have a huge production, about 400,000 barrel per day.

So that is more or less the percentage.

I think that we are close to end, and I thank you for your attendance.