埃尼石油 (E) 2012 Q4 法說會逐字稿

(audio in progress) -- presentation, you will be in listen-only mode. However, at the end of the presentation, you will have the opportunity to ask questions. I now hand over to our hosts to begin to the conference. Thank you.

Good afternoon, ladies and gentlemen, and welcome to our strategy presentation. This is the first time that we discussed our strategy after we postponed our business profile and balance sheet through the divestments of Snam and Galp.

Today, I would like to give you an update on the growth and returns which our new Eni is positioned to deliver.

E&P is the main driver of our growth. As Claudio will detail later today, we have a wave of projects coming onstream over the next 24 months. This, coupled with our track record of exceptional exploration success, means we are posed to deliver a decade of strong growth.

Our production will grow to around 2.5 million BOEs a day, through 1.3 million new barrels, which we are -- which are well placed on the cost curve, and will deliver robust returns.

In Gas & Power, we are positioning ourselves to make sustainable profits, even in a hub-priced world, through accelerated counter-renegotiation, a continued focus on solid segments like retail and LNG, and the evolution in the way we serve our larger wholesale customers. Marco Alvera will be leading the effort on some of these fronts. We give you some more color during the course of the afternoon.

For different reasons, R&M, and our chemical business, Versalis, have been a significant drag on our overall results. Cost cuts, capacity rationalization, and in Versalis, a refocusing on profitable segments, means we are expecting significant improvements for both businesses during the plan period, even with no help from the scenario.

With regards to capital allocation, on the future shape of our balance sheet, 2012 will deliver a financial improvement of over EUR90 billion through disposals. We would continue to be pragmatic by the way we manage our portfolio of businesses and assets in 2013 and beyond. Our objective is to maximize value for shareholders from non-core assets, and from the optimization of the huge E&P portfolio that we have accumulated through exploration, something that made a good start on with the CNPC transaction announced today.

With regards to capital allocation, and the future shape of our balance sheet -- yes, oh, this (inaudible), excuse me -- the new Eni is more exposed to E&P, a trend which we'll continue to see throughout the plan period, as we will focus the vast majority of our investment on this business. More E&P means much higher returns, but also means greater volatility, and much greater political and operational risk than the regulated business we are exiting. This is why we are fully focused on managing these risks through a strong balance sheet, strict discipline on project delivery, and diversification of the different risks we take.

Take North Africa, as an example. Legacy countries, Egypt, Libya and Nigeria, form a significant part of our business, accounting for almost a quarter of E&P capital employed. Well, the impact on Eni of the region's troublesome transition have been managed. We have not lost a single barrel of production in Egypt, and our strength in exploration has yielded valuable near field discoveries that already contribute 20,000 barrels per day. We have not lost a single barrel of production in Nigeria, and made good progress on delivering growth project with the startup of MLA a few weeks ago, and Merk a few days ago, and CAFC gas later this month.

And speaking about Libya, we have quickly started and ramped up production after the year 2011 revolution. Of course, the situation remains complex, as last week's temporary interruption of production and gas export shows.

However, the situation is now normalized, and we are reassured by Libya's commitment to the integrity and full function of oil and gas facility, including the crucial Mellitah hub, a position which the Prime Minister reiterated to us, when we met him on Monday, last Monday.

Looking forward, our growth in other regions of the world will reduce our exposure to North Africa, both in terms of capital employed and production, which will go from one third today to around 15% of the total over the next decade. Meanwhile, our refocusing on E&P comes at a time when the division's growth opportunities have been multiplied.

Over the past five years, we have discovered around 7.5 billion BOE of new resources, more than double our cumulative production of 3.2 billion barrels. And this is [not on] Mozambique, even excluding Mozambique, so if we exclude the big Mozambique discovery, 2012 would have been in line with our full year track record of around 1 billion BOE, well above average annual production of around 640 million BOE.

This remarkable result sets the foundation for industry-leading growth. Over the next four years, we will grow our production by about 4% a year on average, with above trends in 2014 and 2015 as Kashagan ramps up, and other major projects such as Goliat, Perla, and the West Hub in Angola stepped up.

Our focus is to deliver this growth on time, and on budget. Our visibility is supported by the sanctioning process. We have already taken FID on 65% of new production for 2016, and we'll raise this proportion to 90% by the end of this year, 2013.

80% of this new production comes from projects which are onshore or in shallow waters. Looking further ahead, recent discoveries, including Mozambique, will support growth of more than 3% a year on average in 2022.

This new production will deliver strong returns under almost any oil price scenario, the reason being that our resources come from organic exploration discoveries. We delayed development costs, thanks to our largely conventional onshore and shallow water giant discoveries and projects. To this, we need to add operating costs, which will be higher for new production, driven by complex major projects such as Kashagan, Goliat, and West Hub in Angola, compared to our bedrock of legacy production.

In any case, we are looking at overall cost per barrel, exploration, CapEx and OpEx for these three items, well below $35, $30 for new production before royalties and taxes, which will of course depend on price. That means returns on new projects will be resilient, even the oil price falls, and very strong if the oil price stays at current high levels.

Turning now to Gas & Power, over the last few years, this business has been affected by a number of crosswinds. First, with the rapidly rising oil price. We are not unhappy with high oil prices, which have added billions to our E&P results over the last three years. But looking at the world from the perspective of Gas & Power, which buys most of its gas through oil linked, long-term contracts, they have resulted -- these high oil prices have resulted in increasing supply costs only partially absorbed by the supply renegotiation we have closed to date.

Second, and most important, we have seen demand collapse. In the EU, we have lost 15% of consumption, over 80 billion cubic meters between 2008 and 2012, and supply has not responded to this, with increased spot availability and the rigidity of the take or pay contracts. The result is that selling prices have come under significant pressures.

The combination of these two trends means that when we buy gas on the basis of existing long-term oil-linked contracts, and sell it at European spot prices, we lose money.

This is exactly what has happened to our European wholesale business, which would have made a significant loss in 2012 if we normalize results for one-off items. Overall results were supported by the oil-linked LNG and retail segments, and our stable international transportation and distribution businesses, with a modest contribution despite the poor scenario from our efficient integrated and co-generated power activities.

Looking ahead to 2013 and 2014, we are expecting even more pressure on margins, especially in Italy, where new contracts have quickly converged with a European hub.

In this context, the context we live today and we expect to live tomorrow, our number one priority is to renegotiate with our suppliers. At the moment, we are in negotiations for around 80% of our gas, with the aim of bringing purchase prices down to at least hub prices, less costs. On that basis, what is the potential profitability of our Gas & Power division, which means, if we achieve that, what would be the forecast of the profitability of our Gas & Power division?

Well, let's look at this, segment by segment. First, international transport and [similar] regulated activities, this business includes international pipelines such as Green Stream, Blue Stream, and local distribution assets, and generates stable results. Second, retail Gas & Power sales will continue to be profitable business. We are growing in Italy and in Europe, and targeted an increase of 3 million new clients, to reach a total of 14 million by 2016.

Our third business is wholesale, selling gas and power to large industrial clients. While these customers are extremely price-sensitive, we expect to make reasonable margins by selling structured products with the flexibility on volumes and different ways to manage pricing, something which is made possible by the integration of this segment of Gas & Power with our Trading arm.

Fourth, LNG. This has been a strong contributor to our results, something we expect to continue, even if LNG prices in the different regions of the world will gradually start to converge.

Add everything up together, and once Europe have stabilized, and the renegotiation effect through our numbers, we expect Gas & Power to make something in the region of EUR1.5 billion of adjusted pro forma EBITDA. And in this context of a well-supplied market, where customers do not price in the value of our supply security and flexibility, if the market tightened through demand growth or supply shocks, our diversified and flexible portfolio would again become a competitive advantage with benefits to overall profitability of our Gas & Power business.

Turning now to R&M, this is a challenged business, but one which has made real progress in 2012, through a combination of an improved scenario and self-help measures. With regards to the scenario, we believe there is some room for cautious optimism.

In the face of dramatic demand declines, around 10% in Italy decline in petroleum products unheard of before, a decline of 10%, and 3% in Europe, capacity rationalization is starting to happen. From 2009 to now, 11 refineries shut down in Europe for a total capacity of 1.4 million barrel a day. And a further 15 refineries could potentially close in the coming years.

That said, our planned target is to return to profitability even without assuming any further scenario improvement. Our efforts are on track. Last year, we announced a EUR550 million efficiency and optimization program, the vast majority of which is refining. Over the course of 2012, we have delivered around EUR150 million of recurring efficiency, largely energy savings, labor and logistic cost reductions.

Looking forward, we'll continue to program -- we announced -- we continued the program we announced, for the remaining EUR400 million, mainly through the startup of EST and further savings.

On top of that, we have identified additional improvements from the conversion of Venice into a green refinery, cutting down 10% of our overload refining capacity, and exploiting our proprietary eco-fining technology. We also expect marketing results to improve, given the impact of last summer's extra-large discount.

Overall, at the same scenario as 2012, we expect R&M to break even by 2014, and make something in the region of EUR200 million of EBIT in 2016, with further upside from the potential improvement in benchmark refining margins.

Lastly, an update on Versalis. 2012 was a disaster in the European petrochemical sector in which we operate. We had the worst scenario since 2000, with high naphtha feedstock prices, which we could not pass on to our ethylene and polyethylene customers because of weak demand and competition from much cheaper Middle East producers. As a result, we posted a heavy loss. Given the deterioration in the market, we have increased our efforts on the major turnaround plan launched last year.

The old plan targeted over EUR400 million of incremental EBIT by 2015, at a constant scenario. As a result of cost cuts, the refocusing of the portfolio away from loss-making based chemical, and towards specialties, and establishment of a foothold in fast-growing Asian markets. Our new plan targets around EUR500 million of extra EBIT by 2016 at constant scenario, with more incisive efforts on rationalizations.

And these, on top of the EUR60 million of savings we have already achieved, largely through the closure of the Porto Torres plant. We have also laid the foundation for our portfolio refocusing with agreements in the field of biochemicals, and with major South Korean and Malaysian petrochemical joint ventures.

We expect to make significant progress in 2013, driven by the closure of the polyethylene plant and the reduction of the steamcracker capacity, both in Priolo, the startup of the two green chemicals plant in Porto Torres, and to reach breakeven by the end of the plan period, even at the terrible 2012 scenario.

At the end of the turnaround period, 2017, 2018, we expect additional EBIT of about EUR300 million, including the pro forma contribution of our new joint ventures. This turnaround represents a major change for us, and Daniele Ferrari, who is here, will be happy to answer any detailed questions you might have, both today, and at specific chemicals seminars we are organizing here in London for April 18th.

And now, I will hand you over to Claudio Descalzi for a more in-depth look at the E&P strategy.

Thank you, Paolo. Good afternoon, ladies and gentlemen. Today, I will take you through the evolution of our upstream business, of what is a very exciting time for us. The key growth drivers for the next 10 years are all in place, and we are making good progress toward rapid and valuable production growth.

Now let me take you through the five drivers of our strategy, and how they translate into action and targets.

First, our approach. Everything we do is governed by the Eni model, our distinctive culture, which means operational excellent, continuous improvement, and mutually beneficial development. Second, rapid conversion of our 34 billion barrel of resources into production, with an accelerating time to market.

Third, delivering on our robust portfolio of 120 development projects, which will add around 1.3 million barrels per day of production over the next 10 years.

Fourth, exploration, starting from our very strong acreage base of about 300,000 square kilometers, we are constantly rejuvenating our portfolio to include new material initiatives in our core areas, and in emerging markets. And fifth, leveraging on our cost efficient structure to ensure resilient and robust returns.

Let's take a look at each of these in turn.

First, the Eni model. As you know, Eni has a very distinctive approach, which underpins all our actions and supports our capacity to access new resources. A strong [ATC] performance is a core part of this approach. The total recordable injury rate in 2012 was the best ever, and 50% lower than the average of the previous five years. And on drilling despite an increasing number of operating wells, we have recorded blow-out -- not blow-out, zero blow-out in the last nine years.

Also, sustainability, last year, we are proud to have achieved a record result on gas flaring. Our aim is to reach zero flaring by 2017, completing our major projects, our North Africa and West Africa.

As we are working on these objectives, we will continue to turn gas flaring into a development opportunity.

Today, our power station in Nigeria and Congo account for a good portion of the domestic electricity produced, and this solution is in line with our focus on local development, through energy, but also, agriculture, social and development projects.

This distinctive approach is the foundation of our growth strategy. Growth will come from turning the huge amount of resources we found into reserves and production, with an accelerating time to market. As Paolo mentioned, it was -- 2012 was an exceptional year for exploration, with reserve replacement exceeding the positive trend of the recent past.

We discovered 3.6 billion barrels of resources, with a unit exploration cost of $0.60 per barrel. In addition to Mozambique, we made major oil discoveries in the Barents Sea, in Ghana, Congo, and Angola. This presents about 1 billion barrels of new resources.

As a result, overall resources are up by 7.5% year on year. Most probably, we have increased -- most importantly, sorry, we have increased the P3 and contingent resources by more than 25%, proof of our progress in turning resources to reserves. This is a result of our strategy of selecting material, high risk, high reward opportunities, and accelerating the appraisal campaign.

Our new discoveries have to be transformed into production in a timely and efficient manner. This is our priority. The first step is to sanction projects quickly, which will lead to an average organic reserve replacement ratio of more than 130% over the next four years, at $90 flat. This means that we will be able to put 90% of our recent discoveries into production in less than eight years.

In addition to major projects, we will benefit from a stream of fast track opportunities. For example, in Egypt and in Pakistan, we started up fields within a year of discovery that account for 120 million barrels of reserves, and in the Egyptian western desert, we ramped up to 20,000 barrels per day, only nine months after discovery.

This focus on fast-tracking our projects translate into overall production objectives. Our growth to 2016 will be more than 4% a year on average, at the price level of $90 per barrel flat. This target includes contingency of over 200,000 barrels per day. Our growth will be resilient to our oil price. At $120 per barrel, we would deliver growth of more than 3.5% a year on average to 2016. For the longer term, we confirm growth of more than 3% per year, to 2022.

This is based on a [loaded] client rate of about 4% coming from the economic reservoir management and intense production optimization activities, and our diversified synergic development pipeline. Within four years, our new projects will contribute more than 700,000 barrels per day of production. Of this, 65% is already sanctioned, and 90% will be sanctioned by year-end. 80% of these new projects will come from giant projects, and 40% will come from additional development phases of producing field.

Most of our new projects are in our development hubs, where we can leverage on two types of synergy -- geological expertise, and scale advantages on operational and logistics.

Our production will be increasingly resilient. It is already well diversified among different geographical areas, and will become even more balanced across our hubs. More than 75% of our production will come from either onshore or shallow water, with a positive impact in term of risk and operating cost. And finally, in the next ten years, almost 80% of our production will be operated.

The next 22 months will be crucial for our growth, with the 15 major startups which will deliver 450,000 barrel per day of new production by the end of the 4-year plan, or 60% of the new production we target. On this fundamental objective, we are in a very good shape. Progress is in line with schedule. Main projects for 2013 have either started up, or undergoing commissioning, and close to completion.

On these projects, we are deploying our best people to exercise strict control of operated activities. And now, an update on these projects.

In Algeria, MLE started at the beginning of this year, and is ramping up alongside the contribution of CAFC [area gas] expected this month. The two projects, they are in the prolific Berkine basin, close to our existing operations.

El Merk has recently started up. Equity contribution from the three Algerian projects in 2013 will be 30,000 barrel per day, and will grow to 45,000 at the end of the plan period.

Turning to Kashagan, we are making good progress. At the end of February, we started up the onshore facilities with sweet gas and diesel. The plant is ready to receive well production.

Offshore, the A-island will be ready for production by the end of this month, which we are progressing well with commissioning. We expect a June startup in line with contractor commitment. Contribution to 2013 production will be around 20,000 barrel per day, ramping up to more than 60,000 barrel per day in 2015, following the second start up of the second [Rogas] injection facility in Q3 2014.

Let's move to projects starting in 2014. In Russia, where over the last (inaudible), where Urengoyskoye and Yaro Yakhinskoye are proceeding according to plan. These two projects will add 100,000 barrel per day of equity production to 2016, bringing the overall contribution from the Yamal hub to 165,000 barrel per day.

In the Barents Sea, the Goliat project has reached 54% progress. Drilling is on schedule, and FPSO construction is progressing in the (inaudible) area, with the sailaway planned for the beginning of the next year. Startup is expected in Q3 2014, with an average yearly equity production of about 20,000 barrels per day. Equity peak production reaches 60,000 barrel per day by 2015.

Another project that is making good progress is the West Hub in Block 15, confirmed for 2014, with equity production reaching 25,000 barrel per day at the end of the plan period.

For the East Hub, [conceptualization] has been agreed with partners, and the project will be sanctioned this year. Startup will be in 2016, with an average equity production of more than 15,000 barrel per day.

In Venezuela, the first phase of Perla gas project is on track, and startup is expected in the second half of 2014, with equity production of around 20,000 barrel per day by the end of the period. On Junin 5, we have just started up in anticipated early production, around one year earlier than planned, leveraging on existing facility.

This is very important, as it (inaudible) allow us to derisk the overall project by improving our knowledge of the reservoir, testing productivity, and assessing (inaudible), with a very limited financial exposure. Equity production will be around 30,000 barrel per day in 2016.

To complete the overview of our projects in the last two years of our plan, we will have 11 major startups, which will add 150,000 barrel per day by the end of the plan. Five of these major projects are already sanctioned. All other will be sanctioned by the end of 2014. All are either in execution, or in the front end engineering phase, and are progressing in line with plans.

Moving to a longer term outlook, Mozambique will be a pillar of our growth. We have completed eight wells and tested five, all successfully. The potential straddling resources account for 48 TCF of gas in place, while 27 TCF are exclusively within area 4. This year, we plan to drill one final appraisal well, on the Mamba complex, and one or two new exploration wells. The appraisal phase will be completed in May, just 18 months after the first discovery.

On development, Eni and Anadarko will jointly plan and build common onshore LNG facility in [Capodegado]. The initial development phase consists of four trains, and 5 million tons per year each, and the site could potentially host 10 trains, equivalent to 50 million ton per year.

We will now proceed rapidly with the technical and commercial activities. We foresee FID in 2014, and first cargo four years later. As you are aware, a few hours ago, we finalized an important transaction related to these assets, and we will be glad to answer to your question after the presentation.

Long-term growth are the Barents Sea and Indonesia. In the Barents Sea, the development of Skrugard and Havis is progressing. The development constant has been selected, and startup is expected in 2018. In the Pacific Basin, we are continuing our strategy of organic growth in a robust market, leveraging on synergy with existing facilities. During this year, we will take the FID for the Jangkrik development project in Indonesia. Production startup is expected in 2016, with an equity contribution of 5,000 barrels per day.

Indonesia will contribute over 100,000 barrel per day of production by 2022, through the Janerik complex, Jau, and (inaudible) Basin.

Turning to exploration, we expect to continue our track record of value creation. In Russia, we are progressing well, thanks to a good cooperation with Rosneft. We have set the operating companies, and we are preparing to drill in 2015. Our program in the area over the next four years encompasses more than EUR300 million of CapEx.

The Gulf of Mexico and Asia/Pacific will be key areas for our exploration, accounting for nearly 20% of our exploration investment in the 4-year plan. In particular, this year, we will start activities in Vietnam, drilling our first well just a few months after obtaining the licenses.

Meanwhile, in our field exploration, it will be mainly focused in our legacy areas of North Africa, Pakistan, and Congo. We will drill more than 230 exploration wells in the next four years, and we confirm our target of 1 billion barrels of discovered resources per year, with a very efficient cost position of $2.00 per barrel.

Rejuvenating our exploration portfolio is a constant priority. In 2012, we added more than 80,000 square kilometers of new acreage to our basket, mainly in the Barents Sea, East Africa, and Vietnam. As a part of the transaction finalized a few hours ago on Mozambique, we are entering Rongchang Block in Sichuan Basin in China, one of the most prolific shale gas basins in the world. We will be glad to answer your questions on this after the presentation.

Our growth will be funded by about EUR47 billion of CapEx in the next four years, an increase of 5.5% over the previous plan. The valuation is driven by three factors. Evolution of the portfolio, with projects being completed in Kazakstan, UK and Norway, and the start of major expenditure in Mozambique, Indonesia, and offshore in Nigeria. Cost inflation, for services and material, and exchange rate, with around EUR1.5 billion increase due to the appreciation of the dollar versus euro.

Development CapEx will be geographically diversified and concentrated on development with fast startup. More than 75% of the CapEx is related to activities and projects with production in the 4-year plan horizon. Exploration CapEx will follow an allocation similar to the past years, with 25% dedicated to frontier exploration, 45% to proven basins, and 30% to near field activity.

Our growth will be both variable and resilient. Operating costs will remain among the lowest in the industry's, notwithstanding the startup of new, large projects, which are mainly under PSE contracts. Funding and development costs will continue to improve, driven by confirmed lower exploration costs and efficient development.

In addition, a steady flow of promotion to proven reserves will be guaranteed by the time efficient sanctioning of our projects.

Our assets will deliver attractive cash generation and returns. Rebasing 2012 cash flow per barrel to our scenario of $90 per barrel, the increase to 2016 will be around 15%, thanks to the increased proportion of oil in our new production. Looking at our return, the internal rate of new projects will be strong, around 20% at our scenario of $90, thanks to contained development costs and our focus on a rapid delivery.

Breakeven price on new production will remain at $45 per barrel, reserving profitability. Starting from 30% in 2012, in active capital employed, we'll be around 20% at the end of the plan period, thanks to production startups and to our strategy to develop giant fields by phases.

In conclusion, we are entering into a very strong period for E&P. We are fully focused on our drivers, accelerating conversion of resources, delivering our projects into production, successful and valuable exploration, and increasing returns through the continuous improvement of our performance.

Overall, we are in a better position than ever before to deliver sustainable long-term growth. Thank you. I will now hand over to Marco.

Thank you, Claudio. Good afternoon, ladies and gentlemen. The European gas business has changed quite a bit over the last few years, and the revolution is not yet over. Today, I would like to go through the main changes that have impacted the market, and more importantly, the decisive steps we're taking to reposition ourselves and return this business to profitability in the core areas.

Starting with the market. As Paolo highlighted, we're seeing further deterioration in 2013, mainly in Italy. There's three reasons for this. First, demand is poor, suffering from industrial production decline, substitution of renewables in the coal and the power sector, and slower demand coming from outside.

Second, supply is not falling in line with demand, due to the take or pay volumes that are being delivered into Italy and to their rigidity.

Third, and this is quite peculiar to the Italian market, there's no reverse flow capacity. So when the gas comes in, it cannot go out, so there's no physical export route out of Italy in the north.

The result of this is that overall, the Italian market is oversupplied, and this is reflected in the dramatic drop of the PSV price that went from a steady premium of around EUR50 per 1,000 cubic meters, to the northern hubs, to price levels now that are below the hubs. And this level, unfortunately, is also below our supply cost base on the long term take or pay contracts that are oil-indexed.

In this challenging context, we're taking concrete steps and action to reduce supply costs and to enhance our commercial offering. Let's look at these areas in more detail, starting with supply.

We are proactively engaged with all our major suppliers in formal price discussions. We regard this as an opportunity to positively reposition this business. We have set ourselves two ambitious targets. The first is on price. We want to align prices with the hub level, less logistic costs. Our second target is to reduce minimum contractual volumes so that we can increase the flexibility in our portfolio, and we can cope with volatile demand.

We are confident in our targets because of our contractual or legal right to a competitive price and a profitable business. To predict the exact timing is more difficult, as implementing these contracts and the structural changes that we want to implement in the contract will take time. And in some cases, it will require more than one negotiating round. Some suppliers have their own interpretation of the contracts and of the markets, and that's why we're considering all options, including arbitration.

If a negotiation turns into an arbitration, what we would normally expect to close in a matter of months may turn into a couple of years. Our approach here is always to favor a good deal over a quick deal, also because the late settlements have retroactive compensation. So their overall economic value of the deal is not, itself, impacted by the timing of closing.

Given the uncertain timing, we will have quarterly volatility in both earnings and cash flow until the negotiations are settled. But based on the current discussions we're having, we believe that we can bring already benefits to our overall supply position in 2013.

A rebased supply portfolio is a first pillar of a profitable and sustainable Gas & Power division. The second is an attractive commercial offer. Let's look at our market strategy in more detail.

Here we have three main building blocks. Starting with industrial and wholesale customers, we have integrated our sales and trading platforms in order to develop new structured products that our clients are increasingly asking for. In today's hub-based environment, even the smaller companies and the industries are asking for quite sophisticated pricing when they buy gas from us. And we have everything we need in this environment to position ourselves into more attractive niches and make profit from this going forward.

Second, asset-backed trading. We have a top-class organization based here in London. Their main activity is to do very low risk arbitrage, whether it's geographic arbitrage between different locations, or time arbitrage between different time horizons, to extract the embedded value we have in our unique asset portfolio. We see steady and growing profits in this business.

Our third commercial activity is LNG. We have recently combined our short and long-term portfolios to create a single, integrated, commercial LNG team for Eni. We will continue to generate profits, mainly through cargo diversions to Asia and South America, even if we expect the price premium to shrink, as Paolo mentioned.

In LNG, we work very closely with Claudio in E&P, and we have just returned from a marketing trip in the Far East, where we are beginning to sell the volumes for Mozambique.

So, adding all these three blocks together, in our merchant activities, we expect that we can make around EUR600 million of EBITDA by 2016. This is once we've brought supply costs in line with the market. Adding back the retail and semi-regulated, we get to the EUR1.5 billion EBITDA target that Paolo talked about.

And we have some upside. Based on the size and solidity of our Gas & Power portfolio, we believe we're well exposed to potential recovery in Europe. There are several potential triggers for the market to tighten. The four we think we should watch more closely are, first, decisions on nuclear phaseouts in Taiwan, in Japan, and indeed, in Europe. Second is continuing growth in LNG imports, not only in China, but also in India, in South America, and indeed, in the Middle East.

The third is a new European legislation on CO2, or on coal. And finally, a more rapid decline in European production, and in North Africa, we're seeing the gas balancing tightening quite quickly, as they consume more and more gas.

So, we don't need all of this to happen at the same time, and any combination could drive price higher, as there is not that much spare capacity in Europe right now. After all, last week was a 7-year high in Northern European hubs for gas prices, based on concerns of limited flexibility.

So, in conclusion, even if the two years ahead will be challenging and volatile, we are making steady progress to restore profitability in our core contracts. We're integrating our operating platforms, and enhancing our commercial capabilities in both pipeline gas and in LNG.

Overall, we're confident we have everything we need to generate significant, sustainable, long-term profits in Gas & Power.

Thank you very much for your attention. I'll now hand over to Massimo for the financial outlook.

Thank you, Marco. Good afternoon, ladies and gentlemen. Eni's strategic growth prospects are supported by a strengthened financial structure, with a net debt at the year-end 2012 almost half of its level at the end of 2011, and leverage at 0.25. This stronger financial position is coherent with our new business profile, more exposed to the E&P business.

Going forward, we expect to maintain leverage within the range of 10% to 30%, using this flexibility to absorb temporary fluctuation in oil prices, in market environments, and in our business results.

As well as lower net debt, we are also holding a stronger liquidity position. Our aim in the current market scenario is to retain cash and cash equivalents to cover around two years of refinancing needs, ensuring sufficient independence from the credit and banking systems.

Meanwhile, over the next four years, we will invest EUR57 billion to fuel the growth highlighted today. This is broadly stable compared with the investment plan we presented last year. Excluding the effect of a stronger dollar we now anticipate, the increase amounts to around EUR1.6 billion, or less than 3%.

The increase is largely related to the improved growth opportunities E&P, including Mozambique, partly offset by the completion of Kashagan. Indeed, our plan is focused on E&P, which account for 83% of the total investment, and 90% of discretionary investment, where discretionary means excluding [extra] essential maintenance, and [HIC] in other segments.

Other increases relate to Versalis, with the additional EUR400 million over four years to support the turnaround in Saipem, which plan to complete the fabrication yard in Brazil, and upgrade some vessel and onshore rigs.

With regard to Gas & Power and R&M, we are increasingly selective in capital allocation, and our combined plan is [15] lower than the plan of last year.

Taking a closer look at our midstream businesses, CapEx will be largely concentrated on efficiency programs, and the refocusing of our portfolio on more attractive niches. In Gas & Power, around 60% of the investment plan is related to power generation. Other investments include upgrades in gas transport and distribution, businesses with resilient returns.

In refining, a key project will be the conversion of Venice into a [barrier] refinery to recover profitability. EST, the EST plant in Sannazzaro, exploiting our proprietary technology for the full conversion of the barrel, will be onstream in the second half of 2013, improving the complexity of our overall refining system.

Remaining CapEx will include the maintenance and upgrade of our refinery's logistic announcement, and non-oil development on our service stations.

Finally, Chemical CapEx will be focused on new initiatives to reduce exposure to basic chemicals, and refocus in better segment and geographies.

EUR500 million is -- the increase of EUR500 million is related to the conversion of Peril in Porto Torres, to the attractive segments of elastomers, (inaudible) and green chemicals, reducing the capacity of ethylene and polyethylene, and increasing the 2016 EBIT by EUR150 million at 2012 scenario.

Our CapEx plan will be more than fully funded by a strong cash generation. We project stable cash flow in the region of EUR20 billion per year over the plan period. Our operation will deliver growing cash flow during the next four years, driven by increasing E&P production, and a gradual recovery in our mid and downstream businesses, mainly Gas & Power.

On top of that, disposals will deliver more than EUR10 billion of additional cash flow. This includes the rest of Snam and Galp, the divestment we have announced today about Mozambique, and other E&P disposal, benefiting from the substantial exploration success recently achieved.

We expect this program to be front end loaded, mainly over the first two years. The plan does not include the potential upside from higher oil prices, and on this respect, our sensitivity is around EUR120 million on cash flow for every additional dollar on Brent price.

And now, I will hand you back to Paolo for his closing remarks.

Thank you, Massimo. The strategy and targets we have set out today will generate significant cash flows, which is the basis of our new shareholder distribution policy. As you know, this year, we have taken a fresh look at the way we return cash to shareholders, because with the sale of Snam, we are now a different company, more E&P and less regulated, more growth and more volatility, less debt and more liquidity.

The new Eni will return cash to shareholders through, one, a progressive dividend policy, plus second, a new buyback program. Let's look at both in detail.

First, the dividend. Well, this will be progressive, growing over time at a rate which broadly reflects the Group's underlying earnings and cash flow growth, while taking into account investment requirements and the overall financial structure. This dividend policy is based on our plan scenario, which includes $90 a barrel, and a gradual European demand recovery.

According to this policy, and on the basis of our projections, the dividend, which I would propose to the Eni Board for 2013, would be EUR1.10 a share, an increase of around 2% on 2012.

Second, the buyback. This will be activated at management's discretion, and when a number of conditions are met. This includes, but not limited to, satisfactory leverage well within our target range, and full coverage for CapEx and dividends throughout the plan period. Just to give you an idea, but it's just an idea, of our mental framework, rather than a forecast -- so no forecasts, just an idea.

For 2013, should we see oil prices remaining at current levels, and should we be making good progress on our business and cash flow targets, we would consider the activation of the buyback.

Now I will bring the formal part of this presentation to a close. But before I open up the floor to Q&A, I wanted to wrap up by highlighting the extraordinary growth period that we are about to enter. The basis of our growth would be the startups we will deliver this year in 2014. 2013 and 2014 are two crucial years for startups.

In our long-term prospects, and ensured by the transformational discoveries which we have made, and the high impact exploration acreage of our portfolio. At the same time, we are making progress on the restructuring of our mid- and downstream businesses, rebasing the Gas business for sustainable profitability in a hub-based world, cutting costs and capacity in R&M, and refocusing the Chemicals portfolio on profitable segments.

In addition, we have further upside from disposal, which we'll pursue to maximize value for our shareholders.

Thank you for your attention, and we will now be delighted to answer your questions.

Ladies and gentlemen, we're opening the floor for Q&A. We will take questions from the room first, so could you put up your hand? Of course, when ask a question, could you stand up and state your name and company name, please.

Can we go for that, please?

Alejandro Demichelis from Exane BNP Paribas. A couple of questions for me. Starting with the buyback, you gave us your thinking about some parameters here. Maybe you can tell us whether you think you can stop the buyback in which kind of parameters of oil price, what kind of conditions?

Second thing, on the R&M targets. You gave us the starting point as 2012. Maybe you can tell us, what's the sensitivity around that target, given that 2012 was a good year for refining in general?

Okay. You answer this, or -- no, you answer the second. Let me just comment the buyback. Now, first of all, as you might have understood by my answer, we want to keep maximum discretion and flexibility on the buyback. I mean, we want to be able to take decisions completely freely, and we are reluctant to give any kind of forecast.

Having said that, one thing is, I would take it for granted. If the oil price will beat this year at our scenario -- so, $90, which is possibly unlikely, but it's still a possibility, we will not activate buybacks. So the whole idea we have is that the buyback is an instrument to give back cash to shareholders when the scenario is more generous towards us that we would expect in general.

And now let me answer -- maybe I ask Massimo to answer the second question.

Okay. If I well understood you, you are asking some more detail about our plan to reach more than a breakeven in 2016. So just to recall that we already got some significant improvement in 2012, reducing our functioning costs, mainly in supply and energy, and reducing energy consumption, amounting to more than EUR100 million. If I have to say more precisely, [1 and 20].

And the reduction, the expected reduction of our refining capacity by around 10%, with the closedown of the -- or, reduction in capacity of our Venice refinery, will help to reach this result.

And then, the EST investment that will be ready for production by mid of this year, in the Sannazzaro refinery, will help to complete substantially the plan.

So our overall synergies are expected to reach around EUR500 million. That means that 2016, using the same scenario we have experienced in 2012, an EBIT result that would be around EUR200 million.

Can I have that microphone down here, please?

Hi. It's Iain Reid from Jefferies. Paolo, can I ask you another question about the buyback? And it's on the disposals, particularly of Galp and the remainder of Snam. If you manage to sell those this year, is that some sort of trigger for you as well, even though oil prices may not be perhaps high enough on an organic basis to start the buyback?

And I've got a follow on from Claudio as well. Just a minor quibble on your presentation. Going back to what you showed us last -- whenever it was, September, October, you showed F&D costs at that time falling quite considerably to about $15 per barrel in 2012 to 2015. You've now showed them pretty much flat, it looks like about $20 a barrel going forward. Is there any reason for this quite -- kind of sharp increase in F&D?

Okay. While Claudio thinks to answer your second question, let me answer the first one, which is complex.

Now, listen, on the buyback, let me first give you a number. No, we think our numbers for the plan, we forecasted EUR10 billion of divestments, EUR10 billion. These EUR10 billion are composed by EUR5 billion which are either the shares of Snam and the shares of Galp, which we plan to sell within the plan period, and the two convertible bonds, exchangeable bonds that we have launched, which are supposed to be paid back by 2016. Or, the sum of all of this, let's say, everything around Galp and Snam is worth EUR5 billion, more or less.

Then, we have another EUR3 billion of Mamba, of Mozambique, okay, which are the $4.2 billion transmitted in euros. So in total, we have already identified -- not yet achieved, but identified EUR8 billion out of EUR10 billion. Then we have EUR2 billion more, because we always made some portfolio management, and here we are taking a four years' period, so a pretty long period.

Now, all these numbers are already in our plan. And since we must have -- is to keep a very strong balance sheet, we want to have a very strong balance sheet for the future, these activities, we would not consider this divestment exceptionals. We include them in our numbers.

So to answer your question, no, this divestment will not be the reason of a buyback. The reason a buyback would be more in oil price exceeding our scenario.

Now, the second question, Claudio.

The second question, F&D, what we said on the average between $15 and $16 that I presented in October didn't consider the updates with the new projects. So there is new projects, and there is now all the efforts of the -- effect of the new FID sanctions. So there is a slight increase of $1.30 per barrel. That is the increase due to the new projects.

Thank you. It's Irene Himona, Societe Generale. I had three questions, please. The first, you show a chart, I think it's slide 41, with a fairly stable cash flow from operations at EUR20 billion. Earlier, you said that the capital employed in-service will move from about -- or, not in-service, rather, from 30% to 20%. So therefore, I would have expected an increase in cash flow from operations from that. I wonder why that is not the case.

My other two questions relate to Mozambique. I think it was mentioned that you're already pre-selling volumes into Asia. Can you indicate if that is on oil price indexation? And secondly, your remaining 50% stake following today's disposal, is that a level you're happy with? Given the size of that project, would you potentially look to reduce exposure? Thank you.

Irene, I'll answer your first question. And is it possible maybe to --

Turn back --

-- to project again slide 41, because -- okay. It's a matter -- you are perfectly right, Irene. It is a matter of color that has been used for this slide. But if you carefully look at the slide, you could see that the operational cash flow will increase all along the four years. So if we start very close to the CapEx line, by 2013, ending up at a very high level in 2016, so the difference to have an overall cash flow stable is due to the disposal that, as I said, will be front loaded. So mainly concentrated in 2013 and 2014. The sum of the two components will end up with a stable cash flow of EUR20 billion per year.

Now, on Mozambique. First of all, to answer your question, no, we have not set any price with anybody, nor pre-sold quantity, no, nothing of that sort. We are -- it's really very premature.

What has been central in our strategy around Mozambique was to -- in order to give value at the huge discovery, to have potential customers among the shareholders. We have done it with Kogas, and Kogas is certainly a big customer of LNG in the world. It's a kind of traditional partner of ours. You might now that it's together with us in Cyprus, it's together with us in Iraq. So we have a, let's say, an easy relationship with them. And now with CNPC, which of course is potentially a big customer for this gas.

The whole idea is that to have customers, and maybe in the near future, having even contracts with them, no, as soon as we move ahead, gives robustness to our project, because when you have already pre-sold gas, everything flows much easier.

Now as far as our 50% stake, now, we were sitting comfortably on 70%, so we are sitting even more comfortably on the 50%. Having said that, again, if we could, through a sale of some of -- a part of those shares, to give more solidity to our project, we would certainly consider.

Hi, hello, it's Martijn Rats. I'm with Morgan Stanley. I wanted to ask you three questions. The first relates to the dividend, which has increased 2% in the presentation that you gave. I was wondering -- which is a little less than the trend growth rate that we've seen over the last few years. And I was wondering, with the different mix between share buybacks and dividends that we're now getting, whether the 2% also signals a lower trend rate going forward in future years, or whether this is sort of a one-off from that perspective.

The other question I wanted to ask is about your basic scenario of $90 a barrel. I just wanted to confirm that if oil prices were to fall to that level tomorrow, would you expect the entire CapEx program to be pretty much unaffected? Or is there still -- if that actually were to happen, would there still be a change?

And finally, I had a question for Mr. Alvera. You mentioned that you would expect that the Asian premium for LNG to slowly erode over time, and I was wondering if you could put some numbers around that, over what time frame roughly, by what magnitude? How are you thinking about that?

Okay, now, the dividend, don't look at this dividend as a trend from last year. This is a new phase, a new Eni, a new policy, new balance sheet, new debt level, and so we wanted to start with a dividend which is fairly generous in the industry. I don't know if we are the top dividend yield company in the sector, but if we are not the top, we are certainly very close to the top.

And so we started with a EUR1.10 dividend, which is something which we consider reasonable in terms of share price, and that's it.

What is, in the future, every year we will take this decision according to, as I said, the total growth of the Company in terms of profits, cash flow, etc.

Now, as far as the $90 per barrel in our CapEx plan, I think that Claudio pointed out that we have a breakeven at $45 dollars. So our -- if the oil price tomorrow would be a $90, our CapEx plan will not change.

Now, in terms of what we do expect about gas prices in the world, and particularly in Asia, I don't think that everyone has a clear view, but maybe Marco wants to add something.

When I was speaking, I was talking specifically about our plan in 2016 compared to 2012 or 2013. So, we've seen last year incredibly high premiums that we don't think are structurally plannable in prudent forecasting over four years. But we are seeing a lot of demand, so they're not going to probably disappear, but we're just planning prudently, and not assuming that that gap between European prices and LNG prices stay stable.

Yes, thank you. Hello? Oh, thank you. Roberto Ranieri from Banca IMI. A few questions, if I may. The first one is, about the exploration unit, exploration cost, and you told us that it is in the region of $2.00 per barrel. My question is if Mozambique is included. If not, what would be the change of this exploration cost per barrel in the future, with -- including Mozambique.

My second question is on the Gas business. Reverse flow, which is important for the Italian gas hub, my question is when we can expect a reverse flow, as opposed to when it is Snam, investments would be completed. So my question is, presumably, the timing of a substantial reverse flow capacity in Italy.

My other question is on the Gas & Power, is -- which is the current portion of the spot market in Italy, and what Eni is now purchasing in this spot market, and if you see this portion to increase in the future, to reduce the supply cost? In that case, what is your target for a take or pay flexibility in your renegotiation? We heard about 30% flexibility from other operators, and my question is if you can target this level.

My final question is on E&P as well. Just if you can remind me, maybe I missed it, the value, new projects at 700,000 barrels per day. My question is, what is the depletion rate update production, which offset, partially offsetted this growth? Thank you very much.

So, the unit is provision cost of $2.00 a barrel is a projection for the future, and considering to discover 1 billion barrel of reserves every year. Considering the Mozambique, we talk about the past, and in 2012, we had $0.60 per barrel. And the average over the last three years was $1.20 per barrel. So the $2.00 is a projection, considering 1 billion.

The -- yes, the depletion rate is 4%, and that is the -- that is on top. That is, what is the contribution, net contribution of our projects in the next four years.

So, on the reverse flow, the first comment I would make is, we don't need a lot of capacity, and we're working with -- it's actually Fluxys, not Snam, on some work that has to be done in Germany to see if the conditions are there to take an investment later this year. It's not very difficult to do, because the pipeline is already in place, and if everything goes as planned, there could be some reverse flow available in 2015 or 2016.

It was encouraging to read this morning that Snam also believes it's a strategic asset, and so there, it's more of a system play than any specific play, but for Italy and for the market in general, to be able to export some volumes, is a positive thing.

Talking about the hub, the Italian hub has become increasingly liquid very rapidly, I would say. It's not yet liquid, as the northern hubs are, but it is becoming very liquid.

In terms of our buying strategy, apart from maybe some small optimization volumes, we are so long structurally gassed that we don't plan to buy significant volumes in the PSVs. That would not really help our take or pay situation.

In terms of a specific flexibility, we are working on our overall portfolio approach, by reducing some minimum contractual volumes. This will give us flexibility at the portfolio level, but we're not setting specific targets for contracts. So there may be some suppliers with whom it's easier to reduce volumes, and some suppliers who may favor reducing prices. And so we take this at a portfolio level, and we're not giving specific volume reduction targets.

Thank you. It's Jon Rigby from UBS. Three detail questions, really. The first, I think last year, you talked about, in your projections for Gas, I think you talked about a 50 BCM increase over the planning period in demand across Europe, as part of the scenario, and I just wondered what you were thinking about this time around as you put that into your plan. I suspect it may be on your upside, but if you can talk about that, that would be great.

The second, I guess, is for Massimo, is that when you look at your cash flow targets, one thing that occurs to me when I look at your 2012 performance is just how much cash flow is soaked up in the working capital movements of the business. And I just wondered, A, what you were projecting over the next four or five years in your projections, and second is, where there's work to do in terms of upside to get some of that cash back, to be perfectly frank.

And the third question is for Claudio, is, on a non-risk basis, I guess is the best way of looking at it, which of the wells or the activities that you've got coming up through the 2013 exploration program that we should keep a very close eye on, given your track record over the last few years? Thanks.

Okay, let's start from gas demand.

Thank you for the question. So, in the numbers you saw, which lead to the [1.5] target, we're staying quite prudent on growth. So we're assuming a 0.2%, or let's say, zero growth in Italy, based on 2012 figures that you know were very low compared to the previous years, and this would bring Italy to basically a level of 2003, 2004, and that's about 75 BCM.

In terms of Europe, again, we're assuming only 0.5% annual growth, and this would bring to volumes in 2016, which is our end year, basically in line with 2010, 2011. So we're taking a prudent growth -- that's why we have this upside situation, where if the market does pick up, we're geared to participate in that.

On cash flow?

On cash flow, yes, the working capital absorbed a significant amount of cash in 2012, mainly due to Saipem and to Gas & Power. And the overall amount is higher than EUR1 billion in 2012, and what about our expectation? We expect that this amount will be slightly recovered in the first two, three years, and would be, in our projection, fully recovered as far as Saipem is concerned, and quite fully recovered, even if not all, not all in Gas & Power, due to the slightly recovering gas demand.

Exploration?

Exploration. Exploration 2013, then. We're going to continue and finish our exploration in Mozambique, so I think that is another interesting spot there of our exploration, finish the appraisal campaign, and we are going to start a new exploration campaign with the first well that will be drilled in July. But now it's a new and different kind of environment, different target, and mainly oil. So that is quite important.

And we're going to West Africa. I think there are three countries where we are drilling, two countries -- one country we are drilling pre-salt horizon, that has been very successful, and we continue in Congo. So in pre-salt Congo, Brazil, and we have to drill other wells there for oil in Ghana. And also, we have other three prospects in the Block 15/06. We -- now we finish the appraisal campaign for the West and the East Hub. We are going to sanction in East Hub, and we can start and restart again the pure exploration in the -- in Angola.

We could -- we start -- we have two wells in the Barents Sea, and that -- I hope that would be very important wells for us. We have the first well in Vietnam, as we said before, and we start -- and really start exploration in the Gulf of Mexico. In Gulf of Mexico, as I said before in the full year plan, it will be very interesting and important for Eni. We have 20% of our budget in Gulf of Mexico.

So, overall, we are going to drill between 60 and 70 wells in the exploration budget that is about $2.5 billion.

Yes, hi. It's Michael Ridley from Mizuho International. Two questions, really. You spoke many times about wanting to have a strong, or very strong balance sheet, and I know you've got a debt for equity ratio target. I'm just wondering if you had any other parameters to guide us there. Do you have a net debt to EBITDA target, or a rating target, say, if you were not impacted by the Italian sovereign rating, what would be your goal as a rating?

Second question, hybrid issuance. BG has issued hybrids, and Enel is looking at EUR5 billion over the next three years. Just wondering, if you have views on that, or you might rule out issuing a hybrid? Thank you.

Could you repeat the second question for us?

Okay, so the hybrid debt security, it's sort of a perpetual, quasi-equity instrument that's quite common now in utilities and some oil and gas companies, BG, for example.

Okay. Massimo, please.

As far as the first question, no, we don't have any specific target in term of net debt. Our target is the one we declare, so the range between 10% and 30% in term of leverage. As leverage means -- 30% means that the maximum level. And just to highlight how strong we would be in term of balance sheet, I mentioned our aim to be self-sufficient in term of refinancing, with the liquidity available in the short-term, to be independent from the banking system.

On top of that, we are retaining significant amount of committed credit lines, and this would be, I would say, our aim, to retain this stronger balance sheet, and defense this possible -- our rating from the outside environment.

So, just to add a number to what Massimo has told you, as we speak, we have roughly EUR18 billion of bonds outstanding. Am I correct? And we have in cash, roughly --

EUR9 billion.

EUR9 billion, okay. And we feel comfortable with that. We feel comfortable with that kind of numbers.

Now, on the hybrid, I don't think we have in mind to issue hybrids right now, no.

Okay. The microphone over here, please.

Rahim Karim from Barclays. Three questions, if I may. The first was just with respect to the diversification that you talked about, Paolo, in the upstream business. You gave us a useful chart on slide 3 around capital employed in the various parts of your business.

There was something that showed quite a large growth in sub-Saharan Africa, almost close to 40% of your capital employed in 2016 being in that part of the world. I just thought -- I'd be interested just to get your views on whether you thought that was diversified enough, and whether we should expect some sort of portfolio action in that part of the world.

The second question was just, perhaps, to get a sense of the kinds of returns that you might be expecting from the new operations and the synergies within the Trading business. So, bringing it together, the Gas & Power, and the R&M, to give us any sense of what profitability uplift that could give, and perhaps any capital employed or working capital that might start to absorb, to go back to Jon's question earlier.

And then the third question was, just to come back to the buyback. I was just wondering if you could help us understand that in the $90 kind of scenario that you've painted for the next four years, would you expect to do any buybacks, should the oil price be there, or is it an oil price above $90 over the next four years, at which the buybacks should start to commence? Thank you.

Okay, thank you for your questions. Now, I answer first the third one. Now, I cannot say never, but in principle, if we stay $90, we will make no buyback. So that's just to give you what is my view.

Now, on diversification, now of course, we -- Eni today is very much dependent on E&P, and it's dependent on the geographical distribution of E&P. We are different from many other oil companies, the traditional ones, which are somewhat national oil companies. Now, if you take the large American international oil companies, most of them produce more than 50% of their production in the US and in Canada. No, while we, unfortunately, we do not have a home country which is so generous in hydrocarbon, so we have been expanding in areas of the world such as North Africa, where we are -- we have a major role, but of course, sub-Saharan Africa, and other countries.

Now, we would like to use our exploration successes in order to have a wider distribution of our resources. We still consider Africa our homeland. We are, by far, the biggest producer of hydrocarbons in Africa. We have the biggest presence in Africa, and we consider that we know particularly well Africa.

On top of that, when you look at the investments we plan to do in sub-Saharan Africa, Mozambique will play a major role, but also Angola, Ghana, a whole series of old and new countries for us.

Now, on Gas & Power and R&M, and synergy with Trading, the only one thing I would like to point out before I let Marco bring to you the synergy, is that we are organized in such a way that Trading, for us, is not a profit center. Or rather, it is a profit center, but then it distributes the profits to the Gas & Power and then the R&M division. So you will never see a number for Trading, because the number for Trading will go into the two divisions that generate the profit.

Now, of course, Marco will give you an idea of how the synergies would be generating additional profits for the two divisions.

So I will talk separately for the Gas and for the Oil business. On the Gas side, the integration of the two activities is really allowing us to serve the customer. So the market has evolved quite rapidly. The new -- the customers want now new products that are much more similar to a product that's traded through a trading organization than just selling normal gas through a sales organization.

So the upside there, you would find on the commercial margin that Gas & Power makes on the industrial and wholesale by selling this optionality. Of course, this activity is done very closely with our portfolio management, and our risk management, because they are the owners of the assets, so they need to come up with the flexibility that we have, and then transfer it to the market.

On the Oil side, the first step that we're taking right now, that we've taken a month and a half ago, is to integrate Angelo's Supply business with the Trading business. And so, until now, we had Supply people taking purchase decisions for the refineries, what crude to buy, when to buy it, and they were separate from Trading. Putting them together, certainly they would have a single view, they would be more effective in the market, so we expect some upside that is included in the projections that you've seen for refining.

In terms of working capital, overall, we expect working capital to improve as the take or pay positions get reabsorbed over the plan period, and because we don't do a lot of -- let's say, commercial third party trading, we don't need a lot of additional working capital. And anyhow, whatever capital we deploy also on the trading side is subject to our strict internal hurdles and average -- and [WACs] and normal metrics that you would have on CapEx decisions.

Could we have the microphone on this side, please? Maybe (inaudible)?

(Operator instructions)

There are people on the phone, yes.

Hi, there. It's Jason Kenney from Santander. Thanks for your presentations today. So, Enel this week has (inaudible) that it might divest its 19.6% stake in SeverEnergia in Russia, and I just wondered if this could impact your position there, or indeed, if you could even see consolidation in that asset, given that your cash flow is quite positive in the minute.

Secondly, could you give me a guidance on the tax charge going forward, with the new Eni structure? And then thirdly, has the Board -- well, given recent events, has the Board reconsidered the position of Saipem within the Eni Group? And could you maybe just reiterate the pros and cons for keeping your interest in Saipem?

Now, on SeverEnergia, yes, we would like to be interested in Enel's stake. Unfortunately, the new law in Russia forbids anybody -- any foreigner to own more than 25% of an asset. We are already at the level of 30%, so I am afraid we cannot be a bidder for this very valuable asset that we have.

On tax charges, maybe --

Okay, on tax charges, I would like to give you an answer, speaking about tax rate. So we recorded a tax rate in 2012 that was around 61%. What about our expectation? We expect a slight increase in tax rate in 2013, around 64%, 65%, due to the fact that the majority, if not all the income, will come from E&P, that you know is exposed to a higher tax rate around the world.

And then the tax rate is expected to fall down, all along the 4-year plan, because of two reasons. First of all, because we expect a decline in tax rate, even in E&P, because of the increasing production in country which have a lower tax rate, and secondly, because we expect an increase in the pretax income produced by the other businesses, such as Gas & Power and R&M, as we described before.

Now, on Saipem, we, for the time being, we do not see a reason to give ourself a timing to look again at our Saipem stake. Just let me point out that Saipem, for Eni, has been a phenomenal investment. From the time in which Saipem has been listed, the share price multiplied by 18, if I am not wrong, so 18 times in the last, say, less than 20 years.

So it has been an extremely good investment, even at the share prices of today. It remains a very good investment.

So we, as I think I said before, we are always ready to look at our portfolio with the view of creating shareholder value, and this might happen even in the case of Saipem. But for the time being, we see no rush to look into it.

Good afternoon. Theepan Jothilingam from Nomura International. Could we talk a little bit about your unconventional strategy? Firstly, just on today's announcement, if you could talk a little bit about the opportunity in terms of resource, and whether you specifically negotiated for that block, and what you saw in the block in the Sichuan Basin?

Secondly, just in terms of, do you see further opportunities in North America to build a position like some of your peers have done, or do you think it's too late? And then thirdly, perhaps, with the changes recently in Venezuela, is there a greater opportunity for Eni to put more capital to work in that country? Thank you.

Could you repeat the third one?

Oh, sorry. In terms of Venezuela --

Venezuela. Venezuela --

-- is there an opportunity --

(multiple speakers), yes, yes, yes. Now, let me -- before we -- before I give Claudio the opportunity to speak more specifically about unconventional, and particularly unconventional in China, let me try to give you a couple of thoughts.

Now, first of all, as far as unconventional gas is concerned, the real issue is how to make any money out of unconventional gas. Our impression is that so far, not many investments in the area have been really very profitable for anybody.

So, let's say, there is prudence, because one thing is, everyone likes the idea of producing unconventional gas, but we like more the idea of making money out of unconventional gas, which is a different story.

Now, second, we invested in North America with Quicksilver. I think we have been probably the first European company entering into the -- this new area. It was 2008, or 2009 --

2007.

2007, even, so it was a long time ago. We made a small investment -- if I remember well, $300 million. The whole idea was to learn, rather than to become a player in the North American market for gas. And we certainly do not regret not we made big investments in unconventional gas in the US.

Then, maybe, Claudio will expand a little bit on -- but specifically on China, and also on unconventional oil. But let me say a word about Venezuela.

Now, Venezuela, so far for us has been a success story. We started production yesterday on Junin 5, well in advance as compared to our plans. We made a big discovery in Perla. So in terms of hydrocarbons, our presence in Venezuela is extremely strong, because we not only we have oil, but we have gas, and gas might be used to upgrade the heavy oil. So in total, we believe that our position is strong, and we are looking to continue our plan of expansion in Venezuela.

So for China, I think that the Rongchang Block, that is in the Sichuan Basin, is probably the best area in China. We can say that is the best ever, because really, we have different -- well, drilled with very good success. And so, from a technical point of view, it's a really very good block, 2,000 square kilometers of block. We think to have about 6 and 10 TCF, in term of reserves.

Our preliminary visibility study and study of feasibility -- of development, I think bring a possible production between 150 and 2,000 barrel per day, oil equivalent, and in a market that is a very good market. So, China needs gas, the area is very good. It's also close to a grid and network of pipeline. It's southwest of -- 1,000 kilometers south of [Beijing], so it's a very good area.

We have a special, really, a special study on the environment, because there are a lot of people. We have water, but really, the -- and the [ATC] impact study has been really started. We have one year of study with CNPC. I think that is a very good block, that we can develop very quickly after the signature of the [PSE].

So we start this new venture, and as we started this block in the last three years, it's not a new thing for that reason. We had this transaction with CNPC, not just to give value to our Mozambique block, but also to -- be able to stay pinned in this very good area, and we are one of the few companies that succeeded.

Thank you. It's Colin Smith from VTB Capital. I've got two questions. I think at the beginning of last year, you had closed gas contract renegotiations with everyone, apart from Statoil. Can I just confirm that in order to reopen these, you're playing your joker clauses for all of the contracts that you had completed last year? And can I further ask whether you expect to get much of a positive response, particularly as the spot price in Europe is trading closer to the oiling price than it has for quite some time. And as you mentioned yourselves, there's evidence of tightness within the market.

My second question is on dividends. I think you mentioned the dividend policy would be driven by growth in cash flow and profit, but those two things look like they could be moving in quite divergent ways. And I just wondered if you could provide a little bit more clarity around, for example, whether you have a payout ratio in mind in relation to profit, and in relation to cash, what sort of balance you'd be looking to achieve before removing the dividend in that respect? Thank you.

So, Marco on the first one.

Actually, we are now having open renegotiations with Statoil, with GasTerra, with Gazprom, with Sonatrach, and in Libya. Of these, only one may end up in using a [jolly]. So the others are -- happen to coincide, but they are the natural evolution, either under previous agreements, or the original contract. They're kind of all happening now.

In terms of benefits, we're not concerned if that spread shrinks. In fact, if that spread shrinks, our current position improves, so that's fine. We're working on two fronts, on the pricing side. The first front is to make sure that gap doesn't exist anymore, because there's no reason why, structurally, we should pay more than what we can sell at.

The second effort is to try to improve the indexation so that it's not 100% oil, and we introduce, over time, some hub indexation to avoid any commodity mismatch.

So these are the two efforts, and they are ongoing, let's say, regardless of what that spread is at any point in time. They're -- so we're trying to rebase the position so that it's sustainable going forward.

And a lot of these contracts were structured, taking the Italian market into account. So the changes that are happening in the Italian market are very relevant for our supply discussions.

As far as the dividend, and how the two parameter you mentioned, so price and CapEx could play in order to drive our decision in future, I would say that as far as capital are concerned -- CapEx are concerned, we do not expect any significant change in the future, in respect of what we discussed today. Why? Because as Claudio already mentioned, 65% of the total CapEx of E&P, that amount, 90% of the overall maneuver, already reached an FID. Means that the bid's already open about the cost, so the cost is quite sure. And the remaining part will be achieved up to 70% by the end of this year, 90% by the end of this year.

As far as the remaining part, we already embedded some inflation in the remaining cost. So due to the fact that we have this flow of projects that are already full, and a good, I would say, estimate about the cost, the result is that we expect that the dividend will be driven by the price and our capability to put in place exactly the program, meaning in -- especially in production, and in Gas & Power, mainly, we have just disclosed.

Hi, Nitin Sharma from JPMorgan. Three questions, if I may, the first one on dividend. What, if any, was the impact of current high yield on your decision to go for just 2% increase this year? And two, on buyback, apologize for --

Please, can you repeat?

Sorry. So, starting with dividend again, what, if any, was the impact of the current high yield on your decision to go for a 2% increase in dividend? Second one, on buyback, I think the original message around the announcement of buyback last year was to return excess cash from cash flow, from the stake sales. Has that message not been diluted today by linking the buyback with oil price?

And finally, on tax charge in Mozambique, could you guide us what sort of CGT would you incur on this deal that you've announced today in Mozambique? Thank you.

Okay. On dividend, to your first question, the answer is no. No, no, we are not -- the yield is not linked to the dividend we have paid.

On the buyback, I think we never said -- or at least, I never said that the buyback rule is linked to sales of stakes of Snam or whatever. We -- I don't remember to have ever said that. Certainly, I never thought that. And we always linked -- I mean, the whole idea, if I may, because I've seen that this share buyback and dividend is -- raised a lot of interest of you, and I would like to spend maybe one minute telling you what is my view.

We live in a world, and now more than before, which would be volatile. Oil price will go up, it will go down. I -- for example, if you want my view, I'm surprised to see the oil price so high, as far as I'm concerned. But I certainly am wrong, but just give you my feeling, no?

And we want to guarantee to our investors, at least for the 4-year plan, a dividend which is stable and progressive, now which makes some progression. Then every time that we have the opportunity, because oil price is high, to buy back shares, we do it with the idea that the growth of the dividend can be assured with the same amount of cash, because we have less shares around.

No, at the end of the day, what we are doing is what in particular US companies have been doing for many, many years, with huge success. I'm talking about our biggest competitors on the other side of the Atlantic. This is the general area.

Now, on tax charges on Mozambique --

On tax charges on Mozambique, I would say that we expect a maximum tax charge of around 10% of the price of the transaction we announced today.

That gentleman over there.

Thank you. Peter Hutton from RBC. Just following on from that last point, and my first question, congratulations on the deal today, but I see that the Mozambique Energy Minister has already suggested that you might like to share some of the value that you're retaining from that. Is that something which you think is going -- the deal today is going to impact the negotiations, given the commercial terms on gas exports are still ongoing? So that's the first question.

The second is more specifically related to the Gas business, and I just -- you know, it's -- one of the elements of your plan, I think, was mentioned to increase the number of customers from 11 million to 14 million, which I think is quite an aggressive expectation, given that the environment is so difficult, and you're in the middle of negotiation with third parties who are also supplying that market.

To what extent is the recovery based on that expectation of significant increase in the number of customers? Thanks.

Maybe, Marco, you start, and (technical difficulty), retail. So please, we have Angelo Zaccari.

Thank you for your question. I mean, in terms of customers, I mean, we have experienced that over the past great increase, talking of Italy, we have had significant competition, but growing a lot.

The plan shows an increase of 3 million over the period, and what I can say today that within Europe, and with the approach, the European approach to your launching, every day, 6,000 new customers are joining Eni. And this is a great result.

And of course, we want to build on this with this new kind of European approach, both for the retail and the mid-market. We are currently present in Italy, which represent a 90% of our activity. France and Belgium are doing pretty well, we are increasing our customer base. And as I said, over the period, we will be growing by 3 million customers.

Yes, and in terms of numbers, over the period, the commercial retail business is actually going to lose relative weight, because of the regulatory environment in Italy. That will change over the time period.

Now, I would just like to add that we are gaining 6,000 net customers, correct? A day.

Working.

Working day. So, work -- so, multiplied by 200 days, if we continue like that, this would be 1 million a year, more or less, which gives you the target of 4 million for the time period.

So, on Mozambique?

On Mozambique, first of all, the Minister didn't ask us anything, so didn't ask us to share anything at the moment. And the transaction has been well prepared and discussed, and shared with the President, with the Minister, with the government. It's not something that started overnight, so we already discussed with them this kind of transaction. And also, the buyer, because at the end of the day, it's the government that has to decide who can buy resources that we don't own, because that is a -- I'm sorry, of Mozambique.

On the second point, there is no any -- there is no commercial discussion with Mozambique, because we already have an agreement on the basis of what we signed with Anadarko about the construction of the LNG plant. The only commercial discussion that we are going to have, also with the government, but with the state company, is about the gas that we are to sell. And having CNPC with us, that is a big plus, also for Mozambique, because it's one of the biggest buyer, and having the -- CNPC in the joint venture, in Mozambique, also in the upstream and in midstream, it will be better for everybody.

Great. We only have time for a couple more questions, so perhaps I could also ask the people who are following us on the call to say whether they want to ask any questions. We will continue with the floor for maybe one more.

Thank you. Christine Tiscareno from S&P Capital IQ. I had three questions. The first one, if we assume that you are very successful in meeting all your objectives, and in three, four years -- well, in two years, we see at your price, your share price starts going up substantially, which will mean your dividend will sort of -- your dividend yield will contract. Would you be happy with that? Or, as before, would you aim to be on the top tier of payout ratios? Would you want to keep a [5 to 6] dividend yield, or will you say, well, unlike before, we're offering you so much growth that we think it could compensate for that.

The second question is, if we assume that we are in 2017, and the Gas & Power guy has been very successful again in meeting all his objectives, if you're standing here, would you say that Gas & Power is contributing to net profit, would that be around 15% of net profit, 30%, and equal measure for refining and market on Chemicals? Since this is the new Eni, how do you see it by 2017?

And then the last question, it's (inaudible) one, in Mozambique, you've had time to sort of study the field. Would you be concerned, and would you have to watch out what Anadarko is doing, or is it so big that it really doesn't affect you, how they operate, and how much they produce? Could you tell us a little bit more about the geology? Is the challenge there the lack of infrastructure? Is the field very easy, high quality, or what are the challenges that you see now that you know are better? Thank you.

I will try to answer your first two questions, then I would pass it over to Claudio for the geology of Mozambique. He's an expert.

I can spend two or three hours talking about that. (laughter)

He knows much more than me about geology, particularly Mozambique.

Now, on dividend yield, let me answer you this way. We do not have any objective of dividend yield. None. But traditionally, if you take the last 10 years, 12 years, we have been among the highest dividend yield in the industry. So this means that we have been always careful in rewarding our shareholders at the top of the industry. So, this is a tradition, and sometimes tradition remain in time.

On the second point, 2017, you are asking a very good question. I don't have a precise answer. Let's say, I do not have a projection of 2017, the relative things, if everything goes extremely well.

What we expect to happen in 2016, at the end of our plan, is to stop losing money in Versalis, in Chemicals. Versalis has been a major drainer in Eni, but in the last 30 years, so it has been for a long, long time a reason of loss -- with some years of exception, but in general, this has been the case.

We expect R&M to go back to profit. R&M has been traditionally profitable. It has been unprofitable in the last few years, but profitable, and we don't see no reason why it should not go back to profitability. I think we give a number of EUR200 million EBIT by 2016.

Now, as far as Gas & Power, Gas & Power -- you know, Gas & Power was the most phenomenal business I've ever seen in my life. Okay? Most phenomenal. We made huge amount of money buy and reselling gas, a business which had essentially no investment. It was fairly easy, because molecules of gas is really a commodity, and still, what has been very profitable.

Now, those times have gone -- are gone forever. No, we never go back. I remember a time in which we are making EUR25 per 1,000 cubic meter of gas that we were buying and reselling. This time is finished, and will never come back again. But still, we believe that we are in a position, given our extremely strong European position, both as sellers and buyers of gas to restore profitability, and when we give a number of EUR1.5 billion of EBITDA by 2016, I believe this new number is very reasonable. It is more on the conservative side than on the optimistic side, also because we forecast -- I mean, it can be forecasted, also, an improvement of the market, which has been the real thing that nobody has forecasted before.

Just to give you a final number, in 2008, I was making speeches all over Europe, saying -- just to tell you how wrong we can be, that in 2012, the consumption of gas in Europe was in excess of 600 billion cubic meters. Now, you can go -- now, this year, it has been 478 billion, so I've been wrong of 120 billion cubic meters. It's a combination of difficult conditions in Europe, coal prices collapsing -- coal prices are half what they used to be, and therefore all coal-fired power stations in Europe are running at full capacity and not using gas. Of course, there has been also renewables. In total, the world has been moving in the wrong direction for the Gas business.

Now, we feel all our forecasts are based on this scenario, so if the scenario improves, our EUR1.5 billion of EBITDA by 2016 can be a pessimistic number.

Claudio, on (multiple speakers).

So, you want to talk only about geology? (inaudible). So, (inaudible) challenges, so if we talk about challenges, and we talk first geology, it is not a challenge. The best and easier geology -- also, Paolo can talk about geology of Mozambique, it's so easy to describe. We have a thickness of 500 meters, continuing for 25 kilometers, high permeability. You can drill in the deepwater a well in four weeks. So, easy, easy, easy. So that is not a challenge.

Second point, other possible challenges, Anadarko development. We sign an agreement. So any problem is behind us, because we signed an agreement with Anadarko. We are going to develop and build the LNG together. We are going to develop a unique plan and development for unitized area, and after that, each of the two companies, of the two joint ventures, is going to develop its own section of the reservoir in its own area, so that is done.

We agreed on the first development phase, so infrastructure, we have the length -- we bought the length. We are together, the two joint venture, one led by Anadarko, and the other led by us, so that is done, agreed, signed with them, and with the state company.

We already started the feed, so the front end engineering phase for the four trains, so we start with four trains for 20 million tons per year. That means a total reserves of 24 TCF, so just a small portion of what we can develop, and that is done.

We already start -- we have already a feasibility study for the infrastructure, and we agreed with the government. There is a strong motivation, not just with Anadarko (inaudible), especially in the government, that wants to develop as soon as possible these fields, and these infrastructures. That means roads, hospital, a lot of very positive things for the country.

So I think a lot -- I see in front of us a lot of opportunities, all the challenges has been resolved in the last couple of years, working in a very, good, good atmosphere with the three companies who -- the government, Anadarko, and ourselves. So non-issue in front of us.

Great. Actually, I think we don't have time for any more questions, but we're around for the rest of the afternoon. Feel free to ask us. Ladies and gentlemen, I think we are wrapping this up, and thank you for your questions, and thank you for your attention.