埃尼石油 (E) 2016 Q4 法說會逐字稿

Good morning and welcome to our 2016 results presentation and the full-year strategy update. 2016 was a year of records of Eni, despite of a challenging scenario. We have met all our strategic milestones and delivered outstanding result, beating our main operating target in production, reserves and cash neutrality. We did it while enforcing a strong cost efficiency, reducing CapEx by 19%, OpEx by 14% and G&A by 10% versus 2015.

In the fourth quarter, we produced a record organic level of 1.86 million barrel per day, and notwithstanding the Val D'Agri shutdown, disruption in Nigeria, and initial downtime of Goliat, we achieved our average production targets for the year of 1.76 million barrel per day.

We set another record with a reserves replacement ratio of 193%, our best result ever, and the highest in the industry. Over the last three years our average replacement ratio is an exceptional 115% organically.

In exploration, yet again we had remarkable result, adding 1.1 billion barrel of resources at the very low cost of [$0.60] per barrel. In the mid downstream, we can report that each business is now free cash positive for a cumulative EUR2.3 billion.

In operating cash flow, we generated EUR8.3 billion, enabling us to reach a record of CapEx cash neutrality of $46 per barrel. Considering cash from disposals, we fully covered the cash dividend at $50 per barrel.

And finally, our pro forma leverage was 24%. We are the only major that reduced its debt since the beginning of the downturn. This is a clear evidence of the effectiveness of the transformation process we carried out in the last three years.

Another record we are very proud of is our achievement in HSE, beating our long-term trend of outstanding results. Talking about safety, in 2016 we reached a total recordable injury rate of 0.35 with a reduction of 21% versus 2015. This has been the third consecutive year that we have improved our results and beaten our targets.

Emission intensity in the upstream decreased by 9% versus 2015. This confirms that we are well on track on our long-term target to reach a 43% reduction in 2025 versus 2014. Our focus on CO2 emissions, a reduction is mainly on three areas. For maintain emission and gas flaring reduction, as you can see on the chart, the trend are very positive. The third area is increasing use of renewable as a substitute for gas consumption in our operations and, by the end of the plan, we target a capacity of about 500 megawatts.

And now we focus on exploration. This is our center of gravity in terms of organic growth, flexibility in cost and time to market. It is an essential element to reach our profitable level of cash neutrality.

Focusing on the last three years, we have found 3.4 billion barrels, of which 25% has already been transformed into proven reserves, and 25% is under disposal, and for the part disposed has already generated [EUR2.2 billion] through our dual exploration model.

The quality of our assets and discoveries, and the flexibility of our model, allow us to promote an exceptional level of proven reserves, reaching an outstanding, as we said, 193% in 2016. And it's very important to highlight that 70% of these discoveries are long-life production assets, so they give beyond the plan. Even including the effect of 40% of Zohr disposal, replacement ratio remain at 139%, many times greater than the industry average.

This [also is], for us clearly is organic, all organic. But that confirms the strength of our model and our focus on accelerating and maximizing the value creation.

2016 was an outstanding year in terms of discoveries and replacement ratio. 2017 will be marked by the number of projects that will come on stream. All these projects come from our inspiration, which start from the appropriate exploration asset selections, which is the base of the rapid conversion of resources into production. Exploration is carried out in parallel with a safe development process that fast track our projects, reduce costs and risks, and fine tunes the plan of development.

We changed our strategy on APC contracts. We took the leadership of all the [services], managing all the contract packages, from the conceptual phase, through the front engineering to commissioning. This way, we are always in the position to adapt the project development step by step, following the different activities which are carried out in parallel.

The four main projects starting up in 2017 are really emblematic of this approach.

Angola East Hub has been put in production in around three years, five months ahead of schedule and on budget. It is the second deep offshore development in the Block 15/06 in which we found 3.5 billion barrels of oil equivalent in place in 10 different fields. Block 15/06 is producing above 100,000 barrels per day today and we are ramping up around 140,000 barrels per day during the year.

Another two main projects we start up in June, Jangkrik in Indonesia and OCTP in Ghana.

OCTP is a giant oil and gas field development. We've identified near-field exploration opportunity and that is very important; it's part of our model. We have already, around our development, prospects identified and tested. The first phase will be oil of this project and, next year, we'll start up the gas phase, so we have two projects in one. So we give a contribution this year and we give another contribution, just gas, that we already sold, next year.

Jangkrik in Indonesia will deliver gas to the existing LNG plant of Bontang, where we don't have any investment in the midstream, and we create a new hub of development for closer discovery, such as Merakes, which will be sanctioned in the plan. That is another example of our model.

Like in OCTP, like in Ghana, also in Jangkrik we have some prospects, and we have already found and tested, with two wells, a prospect that became a project with a very high internal return that we tie in to the Jangkrik main cluster. These three fields will deliver a long-lasting plateau of 135,000 barrels per day net to APC -- net to Eni, sorry.

Now, the fourth and the most impressive project we will start in 2017, Zohr. It is the largest discovery ever in the Med Sea of 30 TCF in place, [found], discovery in August 2015. After the first well, we moved very fast. We progressed in parallel with exploration and development. That is what we are doing now on all our big projects.

In only three months, we presented the plan of development, three months after the first discovery, we present the plan of development and launched almost all of the tender for the long lead items so, as you see, we did it really in parallel. So one well, plan of development and we start with the long lead items, that are the most critical issue.

Only six months from the discovery, while testing the second well, we took the FID, so six months. Normally, for a giant field in the industry we talk about some years.

And we continue the appraisal activity. So in parallel, we continued the appraisal activity with seven wells drilled, and that allow us to fine tune the plan of development, because we are in charge of the conceptual phase. We are in charge on the front end engineering and we are able, with a strong flexibility, to go in parallel [an update] with the result coming from the field, our project, our field, our conceptions.

In the end, that is not all what we have. In parallel, also, we farm out 40%, so we made exploration, we made a price, meanwhile we are making the development and we add also the farm outs. So we try to take all the advantage in increase the time to market and we farm out 40% of these assets to major companies, that you know very well.

And that is not just a way to reduce our CapEx, cashing in, but it's also a way to confirm the quality of these projects, because if BP and Rosneft, during this accelerated phase, had a data room, due diligence, technical due diligence and then they buy, if somebody had some doubt, or any doubt, about the positivity of this discovery, that is finished.

Now, the next question is, are you able to start production as you said in 2017, and the answer is, yes.

And now I give the floor to Massimo, if he want, if he's ready, to talk about the mid-downstream financial results and close the 2016.

Thank you very much, Claudio, and good morning to you. So some words about the midstream and downstream actual result, where we made major progress in each business.

In gas and power, in line with the expectations, full-year EBIT was minus EUR390 million, lower than 2015 when we benefit from positive one-off items on long-term gas contracts and from higher LNG margins. In 2016, we reduced this negatives, thanks for the renegotiation of some additional gas contracts, savings on logistic cost for around [EUR200 million], as well as the improvement of our trading result in a highly volatile market.

This improvement, that did not release the full effect in 2016, will structurally halve the gas and power recurring losses on a yearly basis. And together with ongoing renegotiation and reduction to logistic cost, will allow gas and power to reach the structural breakeven in 2017, and positive results later on.

In refining, we already lowered the breakeven margin from $5.2 to $4.2 per barrel in 2016, in advance on our original plan, keeping the breakeven in 2016 tougher environment anyway.

In chemicals, we continue to execute our restructuring that delivered a stable and strong result in a weaker scenario.

Moving to cash; we recorded another year of excellent generation, as working capital optimization has progressed strongly. In particular, gas and power working capital was robust, thanks to the optimization of stocks, the reduction of credit positions, as well as further take-or-pay recovery. As the optimization is nearly completed, cash flow from working capital is expected to decrease during the plan, while the profit and loss cash generation will grow as a result of the turnaround. In 2016, each business was free cash flow positive.

In 2016 our cost optimization program underpinned all our business decisions, contributing to an overall reduction of [EUR3 billion]. On CapEx, we reached reduction 19%, or 24% considering pro forma the effect of Zohr disposal.

This result has been obtained mainly through: portfolio flexibility, boosted by our recent major discoveries; engineering optimization, through phased development, [modularization] and standardization; synergies from existing structure, thanks to the near-field exploration successes and consequent development; and finally, a revision our supply chain through procurement. Since 2013, we have lowered CapEx by 35%.

OpEx has been reduced by 14% versus 2015 and 23% versus 2013, keeping us at the best-in-class level of $6.2 per barrel. Overall, procurement delivered this year saving of [EUR570 million] on CapEx and OpEx.

Finally, we reduced G&A by [EUR0.8 billion] versus 2014 baseline, expecting a structural saving of 38%.

In conclusion, it's worth saying that this result, boosted by our superior portfolio flexibility, together with the benefit of our recent reorganization, has been achieved without the jeopardizing our organic production growth by 2020 and beyond.

And now, before Claudio's final remarks on our actual results, a few comments about debt and leverage. Despite the worsening scenario in 2016, with the minimum oil price you remember of $27 per barrel first quarter 2016, and the average European gas prices lower than in 2015, we continued to keep a very strong balance sheet.

At yearend, the net debt amount to EUR13 billion, considering on a pro forma basis that Zohr 40% dilution, corresponding to a leverage of [0.24%]. Since 2013, while our [peers] have increased their leverage by more than 20%, we succeeded in reducing it. Now, with a leverage of 24%, we are at the lower level among our competitors. We are ready to capture all potential upside from the expected recovery of oil and gas markets.

And now, Claudio, I give you the floor for your final remarks about the actual results.

Thank you, Massimo. Now I'd like to end 2016 result presentation, stressing the importance of the result we obtained in the area of cash neutrality. In one of the most difficult years in many decades, we were able to reduce our CapEx cash neutrality to $46 per barrel, beating our original target of $50.

We covered 95% of our CapEx with EUR8.3 billion of organic cash flow; an outstanding result that put Eni at the top of our industry in term of cash resilience. And including cash from disposal, we fully covered the dividend at a price of $50 per barrel.

This result is just the last step of a journey we started three years ago, allowing us to rapidly reduce CapEx breakeven from $127 per barrel in [2013] to $46 per barrel today. And this is the foundation for our future growth.

Now we are going to see a very short video, summarizing all the milestones in the transformation path over the last three years.

(video playing)

Now after the video, we talk about our strategy. That is an update on our strategy. We start reiterating our main points; that is to streamline our Company, to be leaner, more reactive to face market demands. We continue to minimize risks and optimize costs. We aim for long-term, high margin growth, based on exploration.

We will continue to explore material and conventional prospects in near-field play, in synergy with existing facilities. That has been one of the main theme of these last three years that allowed us to be so good in reducing costs and increasing 15% our production. And also in frontier plays, in this case frontier plays that are not close to our facilities but our close to the final markets. That is another form of synergy.

We will capture the full value of our gas resources, leveraging the integration all along the gas chain. That is a new message in the update of our strategy. We really try to link our strong gas discovery in the upstream with the gas and power.

So from being a leading European operator, integrated with retail, gas and power will become a global gas and LNG player integrated with the upstream. Moreover, we will further enhance the downstream, completing their restructuring. But we are going to continue to finalize and we'll talk later about that downstream restructuring.

Another point; active portfolio management will fast-track value generation of our discoveries, with our unique dual exploration model. So that remains a characteristic of our strategy, looking forward. And finally, we complete our transformation process through an integrated oil and gas, unlocking additional value.

So that are the main points, conceptual points, of our strategy, looking forward.

And now look at our three-year plan target. The final goal of our action plan is to keep CapEx cash neutrality below $45 per barrel, on average, in the period. So that is the new target for the next four years. We want to improve, we want to do better. This will be the basis to capture all the possible future upside, and increase free cash flow generation.

Earlier, we talk about upside [in price], keeping the line steady. To ensure this, in upstream, thanks to our discoveries and FIDs, we confirm a growth rate of 3% per year, despite the disposal of Zohr. New startups, ramp ups and production optimization will deliver an overall contribution of about 850,000 barrels per day by the end of the period.

So what happen in this target? Last year we said we want to grow 3%, you remember? But that was before our disposal. Now we dispose 40% of Zohr, that was a big contributor. We confirm, so we fill the gap of Zohr, and we confirm our growth rate of 3%. That's for the four-year plan.

Then in the long term, 2025, we plan to have the same growth rate of 3%. So we are going to take a very strong commitment after 2020. And we [really are] up to 2025, but we are talking about projects that are very long plateau. This is founded, so this growth after the plan, is founded on a diversified and material set of projects in Libya, Kazakhstan, Mozambique and West Africa, where we have different countries with projects that are going on stream on FID.

Exploration, that is the new target in exploration, exploration will continue to be the source of our future production. Clearly, we said in the last page that we wanted to continue to grow organically using our exploration. The target in exploration is in the range of 2 billion to 3 billion barrels in the period. So we start a new target, a little bit more aggressive that we set normally now for four-year plan that is less than 2 billion.

In mid downstream we'll complete the turnaround we launched three years ago. We confirm the breakeven of gas and power, that is another very important point, in 2017. And the EBIT growing for gas and power to more than EUR600 million in the last two years of plan.

In refining, our remaining target is to lower the breakeven to $3 per barrel in 2018. We are not far from that and that is the main target. Inefficiency, cost discipline and operating efficiency, are still our main objectives. As Massimo said, we have demonstrated that we can deliver growth, even by reducing CapEx and controlling project breakeven. That has been the [line we've seen in the] main result of the last three years; minus 35%, our CapEx, and growth of 15%.

We want to continue. In this case, we want to improve our CapEx guidance reduction target to reducing our CapEx 8% versus the previous plan. We will keep our project breakeven at around $30 per barrel.

Finally, we will continue our strong financial performance growing forward; disposal we generate around EUR5 billion to EUR7 billion, and the operating activity will deliver a cumulative cash flow of EUR47 billion in the period.

And now a focus on exploration, our engine room. Our value creation starts, as we said, from exploration because it ensures organic growth, low cost flexibilities and an early monetization of our discoveries. On the map, you can see our drilling plan in the period. Our target, as I said, is to discover 2 billion to 3 billion barrels during this period and drilling around 120 wells in more than 20 countries.

As we said, our main objective in selecting our prospect is to find assets that allow us to have a short time to market, low development operating cost and, for gas, a fit with the final market. So that are the main objectives when we select our exploration asset, because our cost saving or our capabilities to reduce CapEx, increase production, is coming from the exploration selection because we are growing organically from our exploration. So that is something that our exploration has clear in mind when they select all the different prospects coming from the different subsidiaries.

All these basins we are going to explore are well known and that is another important factor, in terms of geology, contractual structure, operations and fiscal terms. So we are not working in a greenfield, and that is another big upside when you want to be fast in your time to market, because you can run faster like the Egypt, [Kazak], or Angola or Congo or Ghana when you know exactly your legal frame, your commercial frame, so you can run your economics and calculation in a very strong way, a robust way, so that is an important point. All these area are area where we have a good understanding of all the different parameters.

Our main exploration activities will be conventional and mainly concentrate in the East Med, West and East Africa, the Barents Sea and the Far East. All wells, and that is another critical point, all wells will be low cost and low risk. We are talking about conventional assets, we are not talking about challenging wells. So the wells are short in timing, very low operational risks and so, very low cost. And that is we maintain what we did in the last two years.

And finally, our exploration expenditure will be in line with the previous plan, so we are not increasing our exploration expenditure.

And now we talk about our FIDs that is our present and mid- and long-term future. As a result of our exploration, we have a huge amount of opportunities in the four-year plan and beyond. Overall, these FIDs represented in the Med count for more than 8 billion barrels of 2P equity reserves, so our equity. They are mostly giant fields which underpin long-term growth of around 3% per year. So they are the main pillars of our long-term growth.

14% of them are close to FID, with the biggest in West and East Africa, they are the yellow one, Indonesia, Kazakhstan and Norway. All these projects have an increasing maturity, both from a technical and operating point of view, and are in areas where we have a major operational synergy and long contractual market experience. So that is, again, another important aspect that sometimes we don't highlight enough.

First of all, the maturity. All these projects are mature from an engineering point of view, but also are mature because, as for the exploration, they are in areas where we don't have to invent anything new. The only project and the only country where we had to work in the last couple or three years, four years, was Mozambique, was a greenfield. A green project, greenfield. The other, so these FID, are coming from countries that we know very well and they are from a engineering process, very mature one. And so they are close; they can be sanctioned.

And now production growth. New project startups and ramp-ups will account for around 650,000 barrels per day by 2020. And if we include 200,000 barrels per day of production optimization, we will ensure a production growth rate of about 3% per year. So that is the composition, the breakdown of the production growth of the 3%.

On Kashagan we are progressing well, now we talk about some project, on Kashagan we are progressing well and production is today 242,000 barrels per day oil equivalent, of which, 180,000 barrels per day are liquid. And within the second quarter, the plant will be fully commissioned, including the third oil train and the second raw gas injection compressor. During 2017, our budget is to have an average equity production of 49,000 barrels of oil equivalent per day. That is our budget for Kashagan.

Angola, we have stabilized production between 90,000 and 100,000 barrels per day. In 2017, we expect an average equity production of 59,000 barrels per day. We will operate more than 80% of our production.

And now some impact of this model. As a result of our model, new projects coming on stream during the plan will increase the value of our production. Over the four-year plan, startups and ramp-ups will contribute significantly with a high cash flow per barrel, reaching $29 per barrel in the last two years of the plan at an average price of $67 per barrel.

That is quite impressive, because you see that our legacy project are at $60 per barrel cash flow. And you see [they add] value that the new projects are bringing in our basket, increasing the average and bringing the average up $20 per barrel cash neutrality at $67. So that are very creative, and they're very creative because the cost of these projects are low cost, high reserves, high production. So the value that are bringing is quite impressive.

And being long-life assets, the positive contribution or the four-year plan startups we talk, also underpins our long-term growth. So that these fields are more or less -- so the fields that start in the four-year plan, we talk about 22 fields, about 50% of them may be plateau that is continue well after 2025. So it's really some (technical difficulty)

And now I focus on the gas business. Our view on gas is positive. It is the fastest growing energy source among fossil fuels, and for the future, we assume a demand growth driven by power generation, and particularly strong in developing countries. Today, in energy markets, we have a situation oversupply as you can see. We expect a rebalance early next decade when demand catches up. Then there will be a need of new LNG projects, opening huge opportunities for our gas assets coming on stream.

Our gas and power business will grow, and our plan is built on the following actions. The first action is the full realignment of gas supply contract to the market, and that is the short term. In 2017, some 90% of our long-term supply contracts are Hub-related already, thanks to the recent negotiation that we concluded in November and December. And this will have a positive impact from this year.

The second is reducing logistics cost to align them to the current volume. In [2015] we cut EUR200 million versus 2014, and we confirm a further reduction in the range of EUR200 million by 2019. That is rising our previous target.

And the third, so we have the short-term that is made up on the restructuring on the long-term contracts, we are very close, and the logistics we still have something to do. But the third point is really the future, and the third point is improving our business model with a further focus on equity gas and LNG monetization, leveraging integration with upstream, and that is the new model.

This action will allow us to reach breakeven, as we said, in 2017. It will continue growing in the medium/long term reaching an EBIT of more than EUR600 million per year in the last two years of the periods that we set in our target. And we expect to grow further in the longer term, mainly through the expansion of our LNG business. The cumulative cash flow from operation in the period will be EUR2.6 billion.

So our new gas and power model aims to better integrate the gas marketing with upstream, to maximize the value of our equity gas, that now is huge, with a worldwide marketing capability. This will be based on two pillars: the first one is the domestic market, where we traditionally have an important role in the energy development of the Austrian countries; that is something that we already tested, was very positive. We can expand, and with the competences of our gas and power units I'm sure that we'll succeed.

And the second point is LNG, where we built on our own competitive and sizable portfolio, so we can create a strong portfolio. You see that we pass from today 3.5 million tonnes per year, but with all the gas we find recently, and discovery from Indonesia, Mozambique, we talk about Egypt, where we talk also about Ghana, we talk about Gabon, Congo, Angola, so really we have huge range of gas discovery ready to -- and [we can develop this gas recovery], so our target is to expand our portfolio and reach, using our equity gas 10 million tonnes per year by 2025. So filling the gap for the period in which we are going to add strong need of LNG.

And now, a look to our downstream in general, so R&M and chemicals. In R&M, we reduced our breakeven margin from $7.5 per barrel in 2013 to $4.2 in 2016, reshaping our downstream oil business. Our main target, we said before, is now to structurally lower the breakeven to $3 per barrel by 2018, and that will be achieved by leveraging, mainly [obtaining] optimization of the existing plants. And then the second phase, Venice Green refinery and startup of [Jerah], where we tag overall 1 million tonnes of production.

In logistics, we are working a lot on the logistics in terms of pipes, in terms of tanks, rationalization, and that is going to cut drastically again our cost. And then growth in the market result.

Through our action we'll double EBIT, and if we include our scenario assumptions, EBIT will triple to EUR900 million by the end of the period. So considering this has the same condition, we are going to double, but if we put our scenario we triple. The cumulative operating cash flow will contribute EUR3.3 billion in the plan period, so it is going to be a very strong contributor.

In chemicals, we target EBIT of around EUR300 million per year, so it's steady, very high, very good, very positive, and a cumulative operating cash flow of EUR1.2 billion in the period, and it will be free cash positive. And that, despite a deteriorating scenario that we assume for our chemical business.

We're going to reach this target through a greater integration, optimization and flexibility. That means putting together all our products and our plans to increase the synergy and the flexibility in terms of product [among them], refocusing the portfolio on high margin specialties. And that is in progress.

We are covering already 40% of our product. That means that we are going far from the effect of the change in price of the feedstock. So it's a protection, and we are on the value chain. Then we had green chemicals, and the international expansion. We are working, we are expanding our international business.

And now, Massimo, again, to talk about some remarks on financials.

Thank you, Claudio. So first of all, maybe some words about the overall CapEx maneuver. The four-year CapEx program shows a reduction, this has been anticipated by Claudio versus previous plan, by 8% or EUR2.8 billion, detailed as follows.

As far as EUR1 billion relates to portfolio, mainly Zohr, as the disposal discharged more CapEx than expected. As far as EUR2.3 billion relates to rescheduling upstream project and procurement. This reduction has been partially offset by the increased effort of around EUR0.5 billion in our businesses, mainly the renewables.

Upstream spending remains, by far, the cornerstone of our investment strategy, covering 86% of the total effort, and assuring a really competitive return. We will operate 84% of the total development CapEx in upstream.

In 2017, we expect overall CapEx in the range of [EUR8 billion], down by 18% versus 2016, at a constant exchange rate. In 2019/2020, if required by negative scenario evolution, the uncommitted CapEx of around 55% will give us the flexibility to adjust the overall maneuver.

And now, let me talk about our enhanced disposal program. First of all, a quick review of what has been already done, mainly to streamline the Group structure, as well as to implement the dual exploration model.

In the last four years, we cashed in EUR18 billion, plus EUR2 billion signed last December to dilute our share in Zohr. This EUR20 billion is mainly composed by EUR10 billion from equity disposals, Saipem, Snam, Galp, and more than EUR5 billion from dilution in exploration assets. In 2016, we disposed of assets for a total amount of EUR2.6 billion. That means we've already got 40% of the original EUR7 billion 2016/2019 target.

And now, the future. We will continue to streamline our portfolio, to focus [mainly] around the core oil and gas activities, and to fast track resource monetization. With this target, in the period 2017/2020, we are projecting additional sales in the range of EUR5 billion to EUR7 billion, of which around 60% in 2017/2018, with a transaction now [mature] expected in the weeks to come.

In detail, EUR3 billion to EUR4 billion are expected from additional dilution in exploration assets; EUR1.5 billion to EUR2 billion from E&P marginal assets rationalization; and, finally, EUR0.5 billion to EUR1 billion from mid downstream. For the sake of clarity, disposal of our remaining share in Saipem, retail gas and power and chemicals, are not included in this amount yet.

And now, let me summarize the effect of what we described on our cash flow. Our cash generation is growing in the four-year plan, even in a stable scenario, and will be further amplified by the recovery in the oil price.

In 2017/2018, at the average $57 per barrel Brent, we expect a cash flow from operation of [EUR10.5 billion], 25% higher than in 2016. EUR9.5 billion will come from upstream, boosting their contribution by more than 50% versus 2016, thanks to the strong pipeline created from [fast startups] already described by Claudio. The resilient contribution of our legacy long plateau asset, which complements the growth. It means that we expect to cover organically our current cash dividend of EUR2.9 billion at around $60 per barrel.

In 2017/2018, we expect disposals in the range of [EUR3 billion to EUR4 billion]. In addition, we will cash in around EUR2 billion from Zohr, already signed. And these together, will provide additional resources for our cash allocation policy.

In 2019/2020, at a constant $57 per barrel scenario, cash flow is expected to increase by [EUR1.3 billion] to a total average of [EUR12 billion]. This will be the result of the additional production increase that will raise the upstream cash generation up to EUR10.5 billion. And this level will be maintained longer, supported by the significant contribution from long-lasting plateau projects. Other businesses which contribute as well to cash flow growth, as a result of turnaround activity, then fully in place.

The overall cash improvement will reduce our organic cash neutrality well below $60 per barrel in 2019/2020. On top of this, three further upsides; scenario, portfolio and CapEx flexibility.

First, scenario; as an example, should the oil price be $10 higher, we would improve average annual cash flow by an estimated [EUR2 billion].

Second, portfolio; we expect contribution of at least [EUR1 billion] per year in 2019/2020, without any contribution from Saipem, retail gas and power and chemicals.

Third, CapEx flexibility; leveraging on the 55% uncommitted CapEx in 2019/2020.

Finally, our shareholder remuneration policy remains unchanged, and even more substantiated by the actual result and updated targets. In 2016, we reached the coverage of dividend of around $50 per barrel, assuming the effect of the 40% sale of Zohr.

In 2017, we confirmed we will fully cover organically our dividend at $60 per barrel, as the growing cash generation from upstream and CapEx optimization will balance lower working capital contribution from midstream.

In 2018/2020, we confirm our cash neutrality well below $60 per barrel, leveraging on our increasing performance as well as our proved CapEx flexibility. On this basis, we confirm our commitment to pay a 2017 full cash dividend of EUR0.80 per share. Later on, to progress the distribution policy, in line with our underlying earnings, cash flow and scenario evolution.

What we have shown in the previous cash flow chart gives you the order of magnitude of extra cash we expect from organic growth, portfolio, flexibility, and additional upside, which will be available to progress our distribution as well as to expand our core business through new accretive initiatives, maintaining a strong balance sheet, with a leverage target in the lower [0.2%].

Now, back to Claudio for final conclusions.

Thank you, Massimo. Just a few words to conclude. Over the past [three] years, we have transformed Eni into a leaner and stronger Company, focused on E&P business. We reached structural, low cash neutrality, which position us to capture any possible upside.

We have built high margin portfolio, made of a large number of mature projects coming on stream, which will ensure our production growth in the medium and long term. And a huge amount of research still to be converted into projects, which will give us flexibility and value.

Exploration will continue to be the basis of our long-term organic growth. We will keep concentrating our efforts on development projects, to fast track production and maximize cost efficiency. We believe in the future of gas, and thanks to our upstream position, we will become a global integrated gas and energy player. The transformation process is still in progress and there is much additional value to unlock.

I thank you for your attention. Now before I go into the Q&A session, we have a very fast video to summarize the main steps of our strategy. Thank you.

(video playing)

We are now ready to start with the Q&A. It will take 40/45 minutes.

Two questions, if I may? The first one is, you've done more than any other company rebuilding your pipeline of future projects. Could you discuss the profitability of these projects at different oil price assumptions for the future?

Then secondly clarification, on your targets for production and for CapEx, do you include a farm out of Mozambique?

I'll talk about the projects and then I ask Massimo to talk about the rest. You saw that our cash flow per barrel is accretive. So we are really, with this set of projects, we are increasing our value, and also increasing the value of our basket.

The internal rate of return is good also at the present level. We talk about double digit and really above our [other rates] for each country. What we can say that with this kind of cost, when you talk about exploration cost last year was [$0.60] per barrel, now we have [$60.2] operating cost, on average. And that will be also for the future projects on average, clearly.

And then we have a development cost [at $11] that are lower than a level, despite the new big giants. But that means that we have giants in our end, we have a focus of more projects, inshore projects. That is a big step to be resilient. So it's clearly that a cash flow per barrel of $29, $67 per barrel of oil is really a good one. So they are very resilient.

Still we run different kinds of stress test on the package. But I think we never had so strong a set of projects in our history, not in the recent but in our history. So as a number of projects, 22 projects that are going into production, but all the other projects really to be [after this].

So really, from a reserves project -- [FID] point of view, we never had it so strong, from an economic and from an operational point of view, set of projects that is covering not for four, not for eight, but really for the long run. We're talking about really [five of] our projects because inside we have the big projects you saw that are going with a steady plateau.

And that is a demonstration, because Eni is one of the few companies that own assets not in the [Gulf] that are really long term, outside the Gulf, Africa, that have a plateau that is lasting for the last 30 years the same level. We talk about North Africa, we talk also about West Africa. So now we are, again, in this new positive way and we have revealed something that is going to last for the next 30 years.

Now if you can answer about CapEx and --?

(inaudible) if we include the disposal program, so net of disposal program.

Thomas Adolff, Credit Suisse. Also two questions. The first question I wanted to go to disposals, and I wondered whether you can say something about your disposal program in Mozambique. We've had to be very patient.

And also on the --

I have or you have (laughter)?

Also linked to disposals, you've just mentioned, as part of your new plan the gas retail, Versalis and Saipem, is not included and these are non-core assets in your own definition. But let's say you are confirmed for the second term, could we see an acceleration of the disposal of maybe gas retail at least?

And the second question I have is on Kashagan. I wondered whether you can give an update on where things are; how things are performing; how wells are doing. And the project has cost a lot of money, I think in total $60 billion. Your share may be around $10 billion. The government isn't going to see much money, so I wondered whether there's a risk of certain changes to the structure of the contract. Thank you.

So I'm going to talk about Mozambique, I'm going to talk about what is not in our M&A, so chemical, gas and power. Just a few comments on what you said at the end and then Kashagan will be passed to Antonio Vella. Don't hide yourself, he's there, so you have talk about Kashagan.

So first of all, Mozambique, everybody must be very patient but I think that recently we made very good progress. I think Massimo said in the coming weeks, Massimo is the CFO, say coming weeks are coming weeks. So I think that we're being patient but I think it's a big project; it's a big deal; it's a big choice. We cannot disclose yet who will deal with us, so I don't answer because I cannot answer. So I think that we are not far. Unfortunately, we are not able to do the big shot today. That was wonderful but then it's out there. So good that we can also [leave it out] for the moment.

So gas and power, chemicals, we didn't put it because we are working on it. Chemicals is doing very well; chemical is getting value, really getting value, free cash flow. And from an industrial point of view, very robust and I think that the CEO, (inaudible), is here and maybe later can give you some disclosure about this.

I'm really satisfied about what they are doing. So is there? We'll see, we have a big option. Are we confirming the strategy? We confirm the fact that we are, one, oil and gas integrated. We'll see the development. It's not there because we are still thinking of it.

Retail gas, we are creating a subsidiary, so a company. Here there is a CEO, Alberto Chiarini. So it's going to work this way and we'll see in the next month. We've already I think next month, next time, disclose it but it's clear that is done at additional value.

So for Kashagan, what you said last, do we have any risk. I don't think that we have risk. They are with us, KMG is inside; we have a very good relationship. The governor of Kazakhstan has been very supportive in the last couple of years when we to recover these (inaudible) issues. And they are being supportive at present and help us.

So now that we are in production, what they ask is really to complete the first production, go to [370,000] and then go fast to the CC01 to get an additional 100,000 barrel per day, and go fast to the second phase. That's what they want, and that's what we want. So I think that has been a project very important, we have [30 billion] of oil reserves [T1] there, so it's really a huge, huge discovery. I think that the future is going to compensate us for the past.

Now if you want to give some update on Kashagan phase?

Thank you. So the commissioning phase has been well completed. As you know, we have already stabilize 180,000 barrel oil. Next step, as Claudio mentioned, that is the gas injection, is going to be done in June/July, without shutdown. We have done all the [network] in place; NCOC have completed all the job; the system of the gas injection is under commissioning at the moment; and the cleanup of the island A and D has been completed. D is cleanup and very soon after that we start to [APC 3]. So the plant is working very well, and the engineering has been well performed through the commissioning. Thank you.

Thank you, Antonio.

Irene Himona, Societe Generale. I have two questions, please. Firstly, back to the 3% production growth target; I think you mentioned, Claudio, you need [650,000] of startups, and [250,000] production optimization. I wonder if you can elaborate on what production optimization actually means, and if there are any contingencies factored into that target?

And the second question, you guide to gas breakeven in 2017. What, if any, specific contractual negotiations do you need to conclude this year to reach that level? Thank you.

So the gas optimization that has been also our -- is our accelerator or re-accelerator with oil now, that is really peculiar to our Company, because when we look at the long life of our project, all projects start in the 1960s or in the 1970s, they are still there producing 100,000 barrels per day, because we do what we call, that is really Eni terms, production optimization, because these are [effect of work] that is mainly [work over, sidetrack], smaller development inside the contractual areas.

Some application of new technologies in terms of [smart] completion on multiple additions, so we go back and we reopen, sometimes in the past we have [with] different [layers]. And because of technology we are going to complete [our commitment] so putting together all the layers, that is the [worst] thing to do because they have different pressure, and you can produce only if the higher pressure, the lower pressure.

That (inaudible), so now we go back and we use, and I'm giving examples, smart completion so you can complete -- you have five players, you complete five layers. [But for us] really you can give to each one the opportunity to talk, because they different voice, different pressure, and they can give contribution. [Those layer] that has been silent for 20 years.

And that is very important, because not only we are going to increase production, but we are going also to have reserves. So when you see that we are going to increase our replacement ratios, because of [exploration], because of FID, but also because there is a detailed work from the reservoir and petroleum engineer, first point, to go and revisit all these wells, completion is very important way [part of things].

And then we have sidetrack, because really process through the 4D seismic, not really the 2D, the 3D, the 4D maybe you heard about the 4Ds, that is seismic that we do, and we compare during the production life of the field that give the (inaudible) [center] or the progression or the production, [and how your] layers are. And on this basis, we are going to cash with a standard reach or horizontal well, or the different [backs or] the different (inaudible) that we left behind, and we can see through this 4D seismic.

So there is a huge amount of work, a very high internal rate of return, because we have everything, we have everything, [mine], we have the plant, everything's there, you drill differently. And that is very helpful in the future to increase our average internal return. We are talking about 200,000 barrel. We talk about internal [run return] at these prices of today that are bigger than 20%.

And this good also for the first party. Why? Because the cost are low. There is a big profit [all] for them. So it's based on technology, competences, keep the same people constantly on the same reservoir, so they know everything, because the reservoir is a human being. If you have your doctor, is much better, because knows everything about you. And the reservoir is you and me. Maybe sometimes is you die before, sometimes it's much longer but, in any case, we need a good doctor. But that is the production optimization.

Second, the gas breakeven. For the gas breakeven we have the new COO and expert from gas present, Massimo Mantovani, that will be happy to answer to your question.

The new one, no; I just have 23 with years with Eni, but (laughter). And then, of course, we do with Claudio even more, actually, and that was one of the focus in respect of the gas and power business. And I have to say that in the last months we were really busy on gas negotiations. Claudio mentioned that we closed four of them and, more importantly, we close Sonatrach in 2017 and we do have the breakeven and I think that now we are working for a positive result.

So this is a clear positive message. We will continue negotiating, but we have a good negotiating table with also other suppliers. So it's going well.

Theepan, Exane BNP. Could we have a deep dive on Zohr, please? Could you just give us an update in terms of what you assume is the capital spend in the current program? Then the process in terms of the startup and how we think about the ramp-up to plateau on Zohr, please.

My second question comes back to capital allocation and capital return back to shareholders. Could you talk about the scenario in terms of when you would think about an increase in cash returned to shareholders, the tension between what is undoubtedly an impeccable balance sheet, compared to your peers and your breakeven?

I was wondering, when do we think about an increase in cash returned. If, for example, you sold assets above your disposal target, do you think of special dividends, buybacks? That framework would be very helpful. Thank you.

So, Zohr; as I said, we are absolutely convinced and determined to have Zohr in production this year. Zohr is going to give also -- after the disposal it's going to give us, for the first part, for the first phase for us in terms of equities, 75,000 barrels per day oil equivalent. When we go to 2019 we pass about 175,000 barrels per day and then after 2020 240,000/250,000 barrels per day. That is the production growth of Zohr today.

We have an overall expenditure that will go as to the plan. It's going to be maybe a little bit less, I hope, because there are good performance from the contractors and they are moving very fast and the market is very good in terms of long lead items. So we think that we are going to [buy off] to reduce -- our exposure is less because now it's being reduced by the 40%. I think that in the plan is something about --

(inaudible)

100%.

(inaudible)

60%, sorry. That's 60% with the other 40%. So that is the -- in terms of returns, you asked also about the return on Zohr. Zohr is acceptable, double digit, much below our average for the country. We negotiate all the [countries] before starting and help us also to recover our working capital.

I think that in this very critical year Egypt -- it's been the first year, from what I remember, that we closed 2016 [without] outstanding. And Egypt is participating in terms of Egyptian funds for 25% in the investment. Normally, we put all upfront and then we recover so they are participating. So it's really strong and well protected because it's the main -- it's a priority, the main project for Egypt.

Normally I have to give the floor to Massimo to answer your question, but your question and your point, it's very reasonable, what you said. Clearly, if we are [adding value], because clearly the dividend is our priority at the same level of the development because we have to fill this dividend, it's something that we are going maybe to discuss in our Board. It's not something that I can disclose now, but it's something that we are going to see.

At the moment, our policies say that we're going to increase our dividend considering the earning growth and when we see a scenario. When we talk about earning scenario, it's really that we don't want to pick up and then go down; we need some stability. But especially the stability now is linked also to the capability, with what we said. We have a very low breakeven, so that is very helpful. And for sure, it's going to give good and positive results, not just from an operating point of view, but, I think, I'm sure also for our shareholders. It's premature but your point is very clear and I don't think that not reasonable.

Jon Rigby, UBS. Two questions; the first is going back to Kazakhstan. I notice you've got two Kashagan projects going into FID [CC01] and then Phase 2, so I just wonder whether you could just talk me through some of the details around that. And also, I noticed that the expansion project at Karachaganak is also in the FID list, and I was just wondering whether there's the capacity within country to be doing Kashagan, Karachaganak E&P and also the Tengiz expansion, which is ongoing as well, and whether there was some tension between all those projects and whether you can discuss that.

Then, given the developments over the last few months, I just also wondered whether you could give an update on your position in Libya, what you're seeing there, and maybe some risked view of what you could be doing, depending upon how the country develops over the next few years, if that's possible.

Okay, on Kashagan, Antonio is going to explain where we are. When we talk about these projects, the CC01, the Phase 2 in Karachaganak, it's clearly there is a strong will from the government to increase production, especially now that we are in a positive trend, and still we are in a positive supply chain situation. So now is a very good moment because you see in perspective your oil [debt] is going up but the market is still in a waiting moment. They are waiting.

There are not a lot of projects because it's not easy to start a project. So we have a wonderful opportunity. We can bet on a growing price, and we have a market that, if you are able to close your contract now, you have a very good discount and that is going to impact on cost and recoverability.

So it's good for Kazakhstan. I'm not saying it's also what I think it's good for Kazakhstan to be able to have contracts signed in these years, in this year, when we have still a very good market condition. They wait when the price will be very high; that means we are going to increase cost for the same amount of production as soon as we have a higher price. But all these costs are going to start to raise the [cost of oil] and reduce the profit for them.

So I think that we have to consider this balance, and when you consider this balance you see that is very positive. And now we have a strong opportunity. So Antonio, if you can talk about this project?

So let's talk about Karachaganak expansion. As you know, Karachaganak is a steady plateau of 260,000 barrels since five years, and the objective is to extend it longer. So the main expansion is from pressure of the gas. One stage is going to be in FID soon this year, and then subsequently, we will go for the other expansion to keep [also] the plateau at the same time. At the moment, the relationship with the authority and the intention to proceed with all the projects are very nice.

Concerning Kashagan, the next FID of Kashagan will allow us to increase the injection of the gas, and jumping up from [370,000 to 250,000], which is the end of the experimental project of Kashagan. Definitely, ending this project, we have to start additional phases, because the oil in place of Kashagan is huge, and we have to ramp up the plateau above [450,000]. And this has been a wider margin project within the four-year plan and after. Thank you.

So Libya situation from our operational point of view is quite steady. We are in developing, we are developing offshore, we are also developing onshore in Wafa, and we are also exploring. So we are quite active in this period. It's clear that, from a political point of view, there is an instability. And we are following -- and our first priority in this situation is, clearly, the security of our people. Our people is not just [Firm], our people in general. So our local people, everybody. So that is a big question, big attention, and that is our priority.

The gas demand is increasing and, as I said several times, when in a country that has some issues, big issues, domestic gas demand (technical difficulty). Domestic gas demand is increasing. It's, I think, a positive signal. It means that there are people, they are cooking, they are eating. There are sound dynamics, because we are delivering a lot of gas and we are using also our experts able to help Libya in terms of gas demand. So we are following.

(inaudible) [Libya] is a huge (inaudible) for us, because we are in the position -- what we have found, without considering the this quarter, what we have found, we are in the position in Libya to double our gas production and condensate production, without considering (inaudible) or (inaudible), [we do that], but we can double. That means that there's another important element that we can add to the east half, because that is really -- in this area, you consider Cyprus, where we are going to be very active in exploration, in Egypt, we're working to put in production Zohr, and to explore additional reserves in Libya.

And the Levantine Basin is really a huge amount of gas that can really help you for diversification, very low cost, very, very low cost. Libya is another case that we love, because really it's our model. So we have everything; [we have just to drill wells], we have platforms, networks, pipes, we have everything. That is going to be a very, very interesting and positive opportunity for Libya and for Europe. So we hope that everything is going in the right direction.

Hamish Clegg, Bank of America Merrill Lynch. A question for you, Claudio, one for Massimo, and one for Luca, checking he's still listening. So first of all, just on the breakeven; you talked about a breakeven cash flow pre-dividend, and you've given us some good sensitivities in the back of the slideshow. Doing an initial quick calculation, on my numbers it looks like you'll be able to cover your CapEx and your dividend over the four-year plan at $53. Does that number resonate with you, sound right? Is there risk to the downside on that number, i.e., a lower breakeven?

My second question is, you've got a fairly bullish longer term outlook in oil prices. You're in countries that are OPEC, part of OPEC, I should say. Could you tell us what you're seeing in some of the early volume moves across the world, and what gives you conviction in a rebalancing of world oil markets? That's really one for you, Claudio.

And, finally, for Luca; just what's the most exciting things in your exploration pipeline, please?

He's not going to say [a lot about that]. So Massimo, you want to answer to the first one? I answer about OPEC sensitivity, and then, Luca about [nothing] (inaudible)?

So the question about the cash neutrality, yes, cash neutrality is expected to decrease all along the four-year plan. Just to recall, the cash neutrality [we are creating] including, I would say, Zohr, I mean the takeout of the 40% CapEx already incurred in 2016, is in the range of $61 per barrel. So we are starting from $61 2016.

This cash neutrality is going to decline all along the plan, while we complete the turnaround in the business, other than E&P, and [grow] up in production takes place, as has been described by Claudio. In average, the number would be probably a bit higher than the one you mentioned, so it would be in the range of [$55, $56] something like this. But with this sense, so the number is going to decline all along the plan.

Luca.

So I'll [not] tell you what's the most exciting, but we have good opportunities, you see. We have good opportunities in West Africa, it's mainly targeting oil prospects. And we had a continuous [reload] of our portfolios during this [couple of the years]. And we have good opportunities coming also in East Africa and also in Norway in the future. And that's what we are going to do. So this year will be still a year of finalizing our appraisal companies mainly, and a few exploration [shafts]. Next year, we will start with a more aggressive exploration campaign on new places.

Alastair Syme, Citi. Two questions. On your gas plan, you talked about getting 10 million tonnes per annum with LNG; just to clarify, does that come from a willingness to take on equity gas through Mamba, as opposed to what you did in Coral?

And the second question is, would you hazard a guess on where return on capital or return on equity would get to under the four-year plan, profitability return?

You're talking about LNG or --?

Overall.

Overall, yes. For LNG, it's not just Mamba or Coral or Zohr, it's really just to find lots of gas. So it's a really huge amount of gas, not just there, because we have gas that we are injecting. But we can increase production a lot in Congo, for example, and we have projects to start. LNG is not in our investment, from other companies that are selling there.

We have a need for gas, [floating LNG] and we have a lots of gas there. So that is another huge amount of gas that we can consider stranded now at the moment. And we have develop [floating LNG]. So it's gas that we have to develop for existing LNG.

And then surely we have Indonesia. In Indonesia, we found gas, now we have additional discoveries that we appraised, and we have new fields that are ready to go on stream. So we have our equity and I think that it's quite wise to stay along the chain and increase our package, instead of buying gas, buying LNG from other producers.

I think that our gas and power must work with the E&P from the very beginning, because the gas, when you open new gas or you have to market new gas, you have to start at the very beginning. You have to show the solidity of your project, you have to show the solidity of your presence in the country, because the buyer wants a lot of assurance and guarantee about your position.

And then there is another element that is quite important, that we have a strong position in these countries as E&P and a lot of investment. And we have to renegotiate sometimes with the same countries the gas price. And I think that is not wise to keep the two things separate. We have really to go and discuss with the country as a unique company; that is quite important. Gas and power has been a European monopoly player and was, a long time ago, but also a company in a company, so they own gas, certain gas in Europe, mainly leaning to the retail gas.

But for the Eni countries, it is a revolutionary new model that put together the two entities but in the upstream, not in the downstream, because we have a lot of gas now. Also before but now we have a lot of gas. Then gas and power can be really useful with the competence to work on the contract definition in the country where we deliver gas for the domestic market. We are, I think, the first Company in term of delivering gas to the domestic market. And where is the E&P gas? So that, I think, is going to give a tremendous advantage and plus for us. Do you want to add something, Massimo?

I just want to underline something you say is that one of the key factors for us in the LNG strategy is that we have competitive LNG and geographically diversified. So you are not just looking for something like Mamba to deliver all the 10 million tonnes, of course. No, because that has a huge value in terms of actually being able also to add, not only polarize the upstream production, take the midstream margin but also add trading.

So the diversified projects, and as Claudio said, we have from Australia, Indonesia, where we close this year the first contract. We will start deliveries from Jangkrik in December. Then you go to Mozambique, you go to Angola, Congo, Nigeria, Egypt. That is the value of the strategy which is going to be at 2025 with 10 million tonnes at least.

Thank you, Massimo. Now you talk about (multiple speakers)? Sorry. Now is there a return, yes, (inaudible) return or (inaudible), what you want? Massimo, it's for you (laughter). If you want, I can answer.

No, the return at [ROCE], the certain level as all for ROCE is quite low in 2016. What we expect is a number growing. We expect to be at 8%/10% in 2019/2020. It will be the result of all actions that has been taken so far, including a significant reduction in the so-called work in progress capital employed that at the end of 2016 is 29%. And it will be reduced down to 21%/22% at the end of this plan.

Let me make an additional comment on this. Now, we characterize ourselves as quite pure upstream, so our capital employed you have seen is 85% now invested in upstream. And I don't know really to measure through ROCE the return for quite pure upstream is correct, because we definitely don't have any kind of advantage from significant amount of capital investment in downstream, or in chemical, that may be currently producing significant return without the need of significant investment.

So for us using this kind of metric is, I would say, a little bit different versus the others that usually you compare with us.

Also talking just about the internal rate of return, on average on all our packages will be higher than -- with this price, is higher than [15%], the price of today.

It's a good point.

Oswald Clint, Bernstein. I wanted to ask you about the engineering comments and approach you're taking; taking control of engineering, being involved in feeds, all the way through commissioning. I don't think anyone has asked Roberto a question, so maybe it's for him. And things like East Hub coming in five months ahead of schedule, are there going to be more examples of that? Or can investors start thinking about your projects on time, ahead of schedule from today onwards? Are the teams mobilized to actually deliver that? Is there any way that you're checking that? Would be my first question.

And then secondly, related to the gas and LNG as you focus on LNG, but in the midstream we still have 90 billion cubic meters selling in Europe and one-third of it going outside of Italy. Do you really need to have 30bcm being sold into Austria and Germany and France and all of these countries? Could a big chunk of that go?

So then Massimo will talk about [that].. In term of organization, Roberto is going to explain because we prepare [a big slide] that then was too long because we did so big work on this in the last four or five years. [You ask] do you have other example? Okay, we have other example. The first example is East Hub that has been four years, two months ahead of schedule and on budget last year.

Another example is Nene, from the discovery, 11 month, the production, now it is 25,000 barrels per day. Another example is Nooros, a discovery with Zohr is producing 170,000 barrel per day. Okay, we start and now we have a Jangkrik and OCTP, and then we have other projects. So I think we have at least most of the production, at least 300,000 barrels per day that now we are [taking] on. Otherwise, the depletion that are coming in the last three years we can say, three years, yes or 2.5 years, are coming from the new model.

That are not just one example, one, two, three, four, five examples. And I think that the future will be like that, because we change everything, but especially we change this [obsession] to be absolutely perfect and spend all your money before starting your production, because it's nice to spend all your money starting your production. We don't want to do that, we want to phase. All our projects are phased and that increase the rate of return and cover the CapEx.

And just to give you another example, because that is with a dual exploration model, Zohr, and Mozambique, will be never, during the execution of the project, in negative free cash flow. So we have two projects that will be free cash flow positive, because we [cash in], before starting production. So that I think worldwide example of efficiency, where you have two giant projects that are not negative free cash flow, never, never. Just a few [helps], at the very beginning, then they start to be in green positive.

So I think that are the example. There is a strong commitment put in the last slide that our obsession is really the time to market. We don't want to leave sleeping reserves that we have found, that are easy to put in production. And that is an obsession of all our people, all our people.

Now that show your [obsession] please.

Well, let's simplify and talk about two main phases; design of a development and execution, because clearly the result of it is the impressive schedule achievement you have seen today. In both cases, the key is the setup of an engineering group in-house. We set up a group of around 1,000 people out of the 3,000 people working on all these developments at the headquarter level. They're working full integrated. That means that we start looking at possible development schemes since the very early stages of exploration and appraisal.

We start building reservoir models since the very earliest stages, in a way that once we have the results coming from explore well, appraisal well, and then later on the development wells, we are able to immediately fine tune both the reservoir behavior and the development scheme, and even the facilities design. This is very important, because in the past we were used to [iterate] no possible changes with a third-party engineering company. Now all this activity is done in-house so you can imagine that everything has been completely squeezed. And this is a key to achieve early FID.

Second phase, execution. We have full control now of all the execution activities, including not only engineering but the procurement activities. Zohr is a key example, because all the procurement of Zohr has been done by us. We just subcontracted construction activities that were not part of our business. And the fact that you have your hands on the execution activity is minimize also the risk of time slippage, cost increases, etc. So the key in this model is firstly working in a fully integrated manner, not in a back-to-back sequence but a fully parallel and integrated manner, and then by running engineering activities for the facilities by ourselves.

On gas supplies is correct. Gas and power is selling nearly 90 billion cubic meters of gas around mostly Europe and we are, on one hand, working on the realignment of the supply cost to the market price and then on the rightsizing of the logistic cost. But at the same time, you also discussing with some of the strategic partners what's the future, in particular in respect of contracts we may be terminating or contracts which may be evolved. Someone which is not -- [he hasn't power] but one of our partners, is a modernization of the contracts. This is a discussion which we have to take place in particular with the key big suppliers and because the future is really changing us, changing the market.

And LNG is changing for the overall structure of the market. We're going short term, flexibility, smaller amounts, and you need a big portfolio diversified. But also on the gas sector is actually changing and we'll have to change also the relationship with the main suppliers.

Just the last question because we're running out of time. Massimo? The last two questions.

Or I'll keep it to one then, Claudio. The question really is just on Mamba and area 4. When we see the transaction in the next few weeks, will Eni still be the operator of the block particularly in the case of Mamba, because I don't know whether I'm reading this right but if you look at your FID chart, which doesn't have any dates on it, obviously, it looks like Mamba is going slightly towards the back end of the FIDs over the next few years now, rather than closer to the front, as it was before. Any comments on that?

I have a comment. It's clearly that we didn't announce the deal yet so I cannot disclose everything. What I can confirm that we remain operator of part of the project, so we remain in and in charge of part of the -- of the part -- of the part of the project. Can I say it more? But part of the project.

Mamba; Mamba is not -- we're not delaying Mamba because of this transaction. This transaction is not delaying at all for our Mamba. Mamba is really a (technical difficulty) as said before. The period of time where we think are more need of LNG that is now from 2022, 2023. Mamba is not in this waiting list because of the transaction [of our] discussion. We are still working with Anadarko, but finalize the tender process in 2016 for the two trains for us because, as you know, Mamba is developed separate from us so we develop our train, they develop their train. We have just a common facilities together. So I think that the best moment to have an FID would be by the end of 2018 or mid 2018 or 2017 because there is no space in the final market.

What we are doing, and that is gas and power that is doing, is working actively in term of marketing the gas. Our traders are working on that; they are working with our co-ventures. Clearly, it will be easier. Easier, why? Because the first, recognize that in a new country, new project, the floating LNG, so the first moment was very important to create a market vision from a buyer point of view on the country, on the companies, on the project. That has been done, and that's been satisfied by one of the most important traders; that is BP in term of LNG. So that has been done; it was a very important step.

Now, I think that we have a very good [roadway] in front of us and there is no any kind of reason of the market.

Massimo Bonisoli, Equita. Two quick questions. Could you give us an indication of the current average depletion rate for E&P and the assumption in bad debts to your guidance to 2020?

And the second question on refining. You confirmed the $3 per barrel breakeven in 2018, despite the accident of the EST plant at Sannazzaro. Should we consider it an underlying improvement in the guidance, and how much is the underlying improvement, if any?

So the depletion rate is always between 5% and 6% so what is in the plan is considered between that, by 0.5% of the depletion rate. On the $3 per barrel, you can see the improvement of [02] because we confirm $3 per barrel. And that is an improvement because that is the weight of the asset that is going to start production in 2018, but in a full year so that is [zero to 0.7]

Okay, thank you very much.