埃尼石油 (E) 2010 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to our presentation. The main theme of today will be Upstream Growth. Our E&P division has a strong pipeline of attractive projects, and a diversified resource base, including new countries and new plays we have entered in 2010, with additional upside from the strategic position we have taken in shale gas.

While E&P is Eni's main growth engine, all of our businesses will improve their results over the next four years. We will highlight, in Gas & Power, both the short-term trading issues, and the midterm recovery opportunities. And in R&M, the work we are doing to bring this business back to profit.

We will also take you through our main subsidiaries, and the key ways in which we will generate value over the plan. But before we go into our four year strategy and targets, let me give you an update on our operations in Libya.

In this situation of confused conflict, the safety of our people is the priority. We have repatriated almost all our expatriates, and a significant proportion of our Libyan staff has taken leave. As a result, production has been suspended at our offshore gas facilities, which were feeding the export market. And the Greenstream pipeline, connecting Libya to Italy, has been temporarily shut.

Production has also been suspended from Bu Attifel oil field, owing to insufficient staffing levels. This means that today, we are producing around a third of our capacity in the country, mainly gas for domestic power generation. Our assets have suffered no damage, and we are technically able to resume production when the situation stabilizes.

While the duration of this conflict remains uncertain, our long history of operations in Libya, and the importance of the energy industry to all the people in Libya, lead us to work on the assumption that the disruption will be temporary. On this assumption, we do not expect impacts on our long-term production profile. We have limited investments planned in Libya over the course of the next two years, and no major project startups within the full year plan period.

While the disruption is ongoing, however, it will affect our business in Libya. For E&P, each day in which production remains at current levels, will cause a 500 BOE per day reduction in full year average daily production. For example, just to make it clear, this means that should we produce at this level for 100 days, we will lose about 50,000 BOE per day on average daily production for the full year.

On the other hand, the uncertainty in North Africa and the suspension of Libyan exports is supporting higher oil prices. We estimate that the North African situation adds around USD$15.00 to the oil price.

Turning now to Gas & Power, the suspension of Libyan gas exports will impact 2011 EBITDA, which was expected to be broadly in line with the EBITDA we had in 2010. While we are able to fulfill all our contractual obligations through higher withdrawals from other contracts, the Libyan contract has been (inaudible) recently renegotiated, making gas from this source relatively competitive.

However, the higher withdrawals from alternative contracts will further reduce take-or-pay payments, prepayments, with a positive impact on cash flows. If you look at the overall impact on Eni profits and cash flows, we see the positive effect of higher oil prices and lower take-or-pay more than offsetting the lower E&P production and lower margins in Gas & Power.

Let me now take you through our strategy and targets for each division.

In E&P, we are targeting average annual production growth of over 3% for the plan period. Our target is underpinned by the sustainability of our current production, with one of the lowest decline rate in the industry, at 3% per annum.

We will build on this base through our strong pipeline of project startups and ramp-ups. In 2010, we have made significant progress in four key areas -- Iraq, Venezuela, Angola, and Russia, improving the visibility of our growth profile.

Our new production will be increasingly diversified, with strong contributions from giant projects in Venezuela, new frontier fields in the Arctic and Russia, and conventional projects in sub-Saharan Africa and Italy. 80% of our new production in 2014 will come from giant projects, which provide long plateau volumes and cash flows, ensuring the sustainability of our growth beyond the plan period.

Our focus on convention oil legacy areas and giant fields will enable us to maintain some of the lowest operating costs in the industry. This, coupled with our continuous effort to improve the time to market of our new discoveries, will ensure high returns.

Excluding cash again, the average internal rate of return for new projects is over 20% at our price deck of USD$70, as well as our low decline rate and the long plateaus from giant projects, our longer term growth would be supported by major startups in the new countries and plays we have secured access over the last couple of years.

In Venezuela, our two giant projects, Junin and Perla, which will start production in 2013, will subsequently enter a second phase of development, reaching a long-term plateau of 170,000 barrels of oil per day. Meanwhile, we will also execute giant startups in Russia, where we have 2.5 billion BOE of resources. Following the startup of Samburgskoye in 2012, four more giants -- Yaro, Urengoskoye, Yevo and Severo -- will contribute 120,000 BOE per day by 2018.

In terms of new countries and plays, we are particularly interested in three main themes. The first is Africa, our legacy area, in which we have some promising new prospects in Ghana, Togo, Gabon, and in Democratic Republic of Congo. I would describe as more than promising our block off the coast of Mozambique.

The second theme is the Pacific region, which is both rich in terms of resources, and provides a stronger gas market. Here, we have several initiatives, such as the first coalbed methane to LNG project in the world, in Indonesia, and the MOU we have recently signed with Petrochina, which opens new opportunities in terms of Chinese gas shales.

Shale gas is a theme we are interested in more generally. We see the shale gas revolution which has changed the shape of the global gas market as an opportunity for our Upstream division, leveraging on the competencies we have acquired with Quicksilver in the US, we are working on prospects in China, North Africa, and Eastern Europe. While the shale gas revolution provides Upstream opportunities, it is also causing challenges to our Gas & Power business, with oversupply driving the price of spot gas below the level of the oil linked contracts.

This challenging marketing environment affects only a portion of our Gas & Power business. Around 50% of our EBITDA in this division comes from infrastructure based businesses, which provide a stable return regardless of the market condition. Another 20% comes from activities which are only marginally affected by the scenario, including international distribution and captive power generation.

The remaining 30%, which is our fuel merchant gas business, is of course exposed to market conditions. For this segment, looking ahead at the next 24 months, we see gradual improvement in the scenario. Demand will continue to recover, partially absorbing overcapacity. Meanwhile, the price of our long-term oil linked contract will be lowered through ongoing contract renegotiations.

As a result of these two trends, the differential between spot gas prices and our oil linked contracts will progressively decrease. We will leverage on our more competitive position to recover volumes and market share in Italy, and continue our international expansion.

Excluding the impact of Libya, this strategy will enable us to preserve 2010 EBITDA in what continued to be difficult market positions, and will put us in great position to benefit from the market's expected recovery.

Looking further ahead to 2014 and beyond, our view of the European gas market is very positive. European demand will recover to pre-crisis level, and then continue to grow, driven by power generation. Gas is the cleanest fossil fuel, and the best way we currently have of combining economic development and meeting the EU CO2 reduction targets.

At the same time, European domestic gas production will continue to decline, by around 4% a year. Meanwhile, we see limited new LNG capacity coming on-stream in the Atlantic Basin between 2012 and 2014. The combination of these trends will rebalance the European market by the end of the plan period. In a normalized market, our consolidated position in Europe and our diversified supply portfolio will again become competitive edges, and we will return to pre-crisis level of profitability, also thanks to the solid performance of our regulated businesses.

Our target for 2014 is EUR4.2 billion EBITDA, in line with 2009, considering the EUR200 million impact of the forced sale of some international pipeline.

Looking beyond the plan period, we expect the European market to tighten further, requiring additional inputs to meet demand. In Europe, we'll have to compete globally for this additional gas. Fast growing countries like China and India, and gas-producing countries themselves, are expected to increase domestic consumption to sustain economic development.

Turning now to Refining & Marketing, our Refining businesses suffered in the last two years from depressed refining margins, and the reduction of the spread between heavy and light crudes. We expect the scenario in Europe to show only limited improvements. Demand for our products will stagnate, and while we see some capacity reduction, refining margins are likely to remain well below historical levels.

Our strategy here is fully based on self-help. In particular, we are focusing on efficiency for which there is still ample scope. We have doubled our planned target for cost savings to EUR200 million.

On top of that, we are working to support margins through a greater supply flexibility to take advantage of opportunities in the pricing of different crudes, and the integration of our refining system, to decrease supply costs and minimize the production of fuel oil.

We will also improve results in our Marketing business over the plan period, leveraging on the branding of our network, continuing growth in key European markets, and the expansion of non-oil activities.

As a result of all these actions, R&M will go from EUR170 million loss in 2010, to a EUR200 million profit in 2014, even assuming no improvement at all in the scenario.

Let's now look at our three main subsidiaries, which will continue to create exceptional value.

We are pleased with the performance of Snam, which has delivered a total shareholder return of 18% over the last 12 months. Looking ahead, the regulatory context is now clear. The Italian government has adopted the EU third directive on gas in a way which has limited impact on our structure, and leaves us free to either retain ownership of our stake, or sell it.

In this, our guiding principle will be shareholder value creation. Meanwhile, we expect Snam to continue to deliver outstanding returns for at least the next couple of years as the full benefit of merging the regulated businesses will come through.

Saipem, which has delivered a total shareholder return of 48% over the last 12 months, is a core part of our strategy, and has material synergies with our Upstream division. Over the last five years, Saipem has strengthened its position in two important markets -- onshore construction, where the merge with Snamprogetti has created a real powerhouse, and offshore drilling and construction, with a significant investment program in new vessels.

In a context of rising Upstream investments, Saipem competencies, technology and fleet will enable it to enter into a new phase of growth.

Turning now to Galp, this has been a phenomenal investment. Its value has increased by several times since we bought our stake. And just over the last 12 months, it has delivered a total shareholder return of 22%.

Having said that, holding a co-controlling stake in a listed company does not fit with our long-term strategy. However, we are not in a rush to dispose of it. Galp gives us exposure to Brazil, the world new oil frontier, and we expect the company to continue to deliver good returns to shareholders.

And now, before I hand you over to Claudio, who will take you through the E&P targets, I would like to introduce Angelo Fanelli, the gentleman down on my right, who became our head of R&M last year, and who most of you have not yet met. And now, over to Claudio.

Thank you, Paulo. Good afternoon, ladies and gentlemen.

Today, we elaborate on our portfolio of Upstream assets and projects. We deliver accelerating growth and profitable accelerating growth in the coming years.

In 2010, we have reached several key milestones that add certainty and visibility to our growth profile. In Iraq, the Dubai project has achieved rapid progress. Our production has been 29% over the baseline, versus a minimum requirement of 10%, with current production about 270,000 barrels per day.

In Venezuela, we have laid the foundation for over 170,000 barrels per day of long life production. In Junin 5, we have incorporated the joint venture with PDVSA, and gearing up initial development activities. In Perla, we had an [excellent] appraisal campaign, increasing gas in place to over 16 trillion cubic feet.

In Angola, we have sanctioned the West Hub development project, and we continue the exploration campaign with five successful wells in the east part of Block 1506.

During 2010, we further strengthened our resource base through exploration success and acreage in promising basins, such as the Gulf of Guinea. Our asset base is largely made up of conventional projects. 74% of our assets are located onshore or in shallow water, with a limited exposure, 6%, to deepwater.

We are geographically diversified, with balanced exposure towards most prolific oil producing regions. In 2010, we also achieved a strong reserve replacement ratio of over 120% through first sanctioning and time to market on new projects.

The achievement we made over the last year underpin production growth of over 3% a year to 2014. This target is based on our scenario and includes a contingency and asset rationalization of 140,000 barrels per day. Our production will rapidly accelerate starting from 2012, and we can confirm last year's target of 2 million barrels per day of production in 2013.

This growth will be entirely organic, based on our low decline rate and solid pipeline of project startups. Over the plan period, we will significantly increase operatorship, which will enable us to control risks, costs, and focus on our giant projects. These will ensure the long-term sustainability of our growth.

Our production profile is also resilient to oil price increases. At USD$100 per barrel, the growth rate will be 2%.

A key pillar of our growth is the sustainability of current production. We confirm our very low decline rate of 3% a year, driven by exposure to giant fields, and our focus on production optimization. Production optimization activities imply a close and productive interaction between reservoir management, well design, and production facility management. Over the next four years, production optimization will account for approximately 20% of our CapEx, over EUR7.8 billion. This will deliver around 220,000 barrels per day of production, which otherwise would have been lost through natural depletion.

The main contribution to our growth comes from the strong pipeline of development projects, which will add 630,000 barrels per day to our production by 2014. About 70% of this production comes from projects already sanctioned, and 20% comes from projects which will be sanctioned by the end of this year.

The 15 major projects listed will account for about two thirds of new production, and around one third of the full year CapEx plan. Most of these projects are related to conventional onshore (inaudible) of shallow water reservoir, and just two projects have exposure to HP/HT wells.

Our project pipeline, which has an average breakeven price of USD$45 per barrel, is geographically diversified, with the main contribution coming from OECD countries and Western Africa. During the plan period, we have no major startups planned in Libya. The temporary suspension of production from this country will not impact our growth to 2014.

Over the four year plan, we expect gross operated production to increase from the current 2.8 million barrels per day to 4.4 million barrels per day. We aim to increase the amount of production we operate, because this is a key instrument in controlling costs, maximize asset value, and directly managing technical risks. Operatorship will allow us to deploy our competencies and know-how to efficiently manage our reservoir and production operations, deploy our safety standard and procedure to strictly control the operation execution, and apply our unique portfolio proprietary technology for drilling and completion.

To support these challenging objectives, we are intensifying our training and knowledge management programs, reinforcing our local technical teams in core disciplines such as HEC well operations, reservoir, and production surface operations.

New production will be increasingly focused on giant projects, which will play an essential role in sustaining growth and in value generation, both during the plan period and beyond. This is due to the very long-term production plateau, and synergies and cost efficiencies. In total, new giant projects will account for 80% of new production by 2014 and over 3.5 billion barrels of 2P reserves, and generate annual operating cash flows in the range of EUR3 billion to EUR4 billion for more than 10 years, based on a USD$70 per barrel price scenario.

Beyond the four year plan, we will start up several giant projects. We are working on three developments in Russia, where we have huge unexploited resources, and a significant gas project in Indonesia, Jangkrik, and others in the Kutei Basin. Our domestic giant in Val d'Agri is also expected to grow its contribution through a second development phase.

Long-term growth will also be supported by our solid and balanced exploration portfolio. In the next four years, we plan to invest EUR3.6 billion in exploration, in line with our previous plan, and to drill 238 wells, targeting 2.1 billion barrels of additional resources.

70% of the spending will be devoted to first time to market exploration, and 30% will be invested in high risk, high reward frontier plays.

Specifically for 2011, we plan to drill 67 wells focusing on [near field] legacy areas, to extend the plateau of producing fields in Egypt, Pakistan, Nigeria, Congo, and Gulf of Mexico, proven basin plays in areas where we have a consolidated presence in West Africa, in Venezuela, in the deepwater Gulf of Mexico, and frontier exploration basins. We are -- we expect tangible volumes for future growth, notably, in Rovuma Basin in Mozambique, in the transform margin in Gulf of Guinea, and in the deepwater basin of West Australia and (inaudible), and in the Bering Sea.

Our long-term growth prospects are also underpinned by the strategic position which are building in unconventional. In unconventional gas, we are working on interesting prospects in Far East, Eastern Europe, and North Africa, areas with large resources bases, profitable gas market, existing infrastructure, and suitable environmental characteristics. Looking at the Far East, in Indonesia, our CBM project will start up in 2012. The project takes advantage of the existing transportation and LNG plant infrastructure.

In Pakistan, we are evaluating a tight gas reservoir with equity resources estimated over 2 trillion cubic feet. Here as well, infrastructure is already in place, and the gas market is profitable and established.

In China, we recently signed an MOU with CNPC, Petrochina, to access the huge shale resources potential which exist in the country.

In Eastern Europe, we are making good progress in Poland, a growing market with existing infrastructure. Here, we acquired three licenses last year, and plan to drill our first well in 2011.

Total resources related to our unconventional portfolio are estimated in the range of 900 million to 1 billion barrels.

The significant production growth in the four year plan and beyond will be fueled by investment of about EUR39 billion. This represent an increase of EUR1.6 billion compared to the previous plan, which reflects cost inflection in the region of 4% to 5%, in new projects in Angola, Indonesia, and Italy. Most of the investments are related to projects already sanctioned, thus, reducing cost uncertainties.

At our price scenario, CapEx on new projects has an internal rate of return in excess of 20%, and production optimization projects have an internal rate of return of about 40%, and a fast payback of less than two years.

Reducing the time to market of our projects is one of the key tools to increase the return on our investment. We have made significant progress on this front. Out of the 3.1 billion barrels of resources we discovered in the last three years, approximately 50% will be in production in less than four years, which compares positively with 35% achieved in the previous period.

Our returns will be further driven by our continued focus on cost efficiency. We have some of the lowest operating costs in the industry, driven by our exposure to conventional assets. While we follow the general trend of cost increase, we'll be able to partially offset this to greater deployment of our technology, and continuing operational improvement. This will enable us to maintain costs which are among the lowest in the industry.

Increasing efficiency in project sanctioning and accelerating time to market greatly improved our [FID] performance.

The quality of our assets, low operating costs, and competitive breakeven prices of new projects result in an industry-leading cash generation per barrel, with a substantial upside from higher oil prices. Looking at 2P reserves, the value of our portfolio remains outstanding. Based on our price deck of USD$70 per barrel, each 2P barrel is worth a weighted average of USD$7.50. At USD$100 per barrel, this value rises by over 50%, to USD$11.50.

In conclusion, we will deliver growth and profitability over the plan period and beyond, leveraging on our strong asset base, focus on giant fields and conventional projects, our high visibility development portfolio mainly based on projects which have already been sanctioned, and the active management of our assets.

By increasing operatorship, we will reduce depletion rates, improve cost efficiency and time to market, and deploy our competencies and technology to manage technical risks.

Thank you very much for your attention, and I'll pass it on to Domenico.

Thank you, Claudio. Good afternoon, ladies and gentlemen, and welcome in this (inaudible). Of course, feel free to take out your jacket if you feel so, really.

Gas & Power results in 2010 were affected by complex market environment, in particular by significant oversupply in Europe. Looking ahead, we see oversupply gradually being absorbed by a combination of different trends. The first is a rapid demand growth in emerging markets -- in particular, in the Pacific Basin. In 2014, China, India, and the Middle East alone will consume over 110 BCM of gas more than today. Japan and Korea will add a further 15 BCM incremental demand.

The second trend is the slowdown in global liquefaction capacity growth. Liquefaction capacity grew by around 110 BCM between 2007 and 2010. Over the next four years, we see a more moderate growth of less than 50 BCM.

The combination of rapid demand growth outside of Europe and moderating increases in global liquefaction capacity means that over the next four years, we see limited new LNG supply to Europe. Of a total 50 BCM on new liquefaction capacity, we expect only 15 BCM supplying the Atlantic Basin. And potentially, some of that LNG may be absorbed by South America.

The third trend is European demand growth, which is projected to add approximately 25 BCM to consumption by 2014. This, coupled with the decline in domestic production, around 20 BCM, (inaudible) forecast European import requirements rising by around 45 BCM over the next four years.

To sum up, over the next four years, European need for gas import will grow more than supply. This trend will gradually rebalance the market, leading to a convergence between the spot and oil linked gas prices toward the end of the plan period.

This scenario underpins our target of returning to 2009 profitability levels by the end of the plan period. While our EBITDA in the first part of the plan will remain broadly in line with the 2010 level, by 2014, we could deliver EUR4.2 billion of EBITDA, which takes into account the EUR200 million impact of the planned sale of our international pipelines, in line with 2009. This target is basically continuing the strong result from our regulated business, and volume growth and margin improvement in our merchant activities.

In terms of volumes, we will grow sales in our key target markets in Europe, in our domestic Italian market, at an average annual rate of 5% between 2010 and 2014. This sales growth will be driven by the increasing competitiveness of our offer, leveraging on the ongoing renegotiations with our gas suppliers.

Meanwhile, we will support margins to a development of an integrated gas trading operation, with (inaudible) London, [here], Brazil, Milan, and Houston, increased focus on the most valuable market segments, such as the retail and small businesses, and by delivering cost saving of EUR100 million.

Let's look at our European operations more closely. Over the next four years, we plan to add 8 BCM of sales in Europe, primarily in Germany, Austria, and France, and maintain our leadership position in Benelux. Our planned sales growth in Europe is in line with our historical organic growth rate.

We will drive the sales to large industrial clients through new customized commercial offers, and by offering a multi-country approach. The strategy will be delivered, leveraging on our integrated pan-European commercial platform. Meanwhile, we will increase the share of more customers in our portfolio, which will provide a greater stability and a value.

Our activities in Italy present significant recovery potential. We expect to increase sales by 12 BCM to 45 BCM by 2014, a true recovery in market share from the low of 39% in 2010 to 48% at the end of the plan period. This trend was already visible in our Q4 results, where a more volume oriented approach related to Italian sales growth of 7%, to a 1.5% recovery in Italian market share, compared to the fourth quarter of the previous year.

In Industrial and Power Gen sectors, we will grow sales, leveraging on improved competitiveness of our cost base, the ability of our supply portfolio, especially valuable for Power Gen customers, and the quality of our commercial offer.

We also defined the new offer structure and customized the contracts to meet the clients' needs, and when supplying gas, we offer a wide range of additional technical services, including energy analysis, infrared tomography, and a core generation of visibility studies. Retail and small business clients are a key target of our commercial activities. We have invested in our customers' sales operations, and aim to position ourselves at the highest level in terms of service quality, while further improving operating efficiency to support margins.

Our growth will be fueled by a selective capital expansion plan, which amounts to EUR7.5 billion over the four year plan. Planned CapEx will be largely focused on regulated businesses, with a guarantee of returns. We are planning investments to improve the system flexibility, and therefore, to expand the [government] storage capacity in Italy by 4 BCM.

In the Merchant business, we will invest around EUR1 billion, mainly in the Power Generation sector, to increase flexibility and maximize margins. Beyond the plan period, we are working on a gas [storage] project in the UK, which will enable us to maximize the value from [Sicily] (inaudible).

Well, thank you very much for your attention, and now I will hand over to Angelo.

Thank you, Domenico. Domenico, grazie. Grazie, Paulo. Ladies and gentlemen, good afternoon.

I am very pleased to be here, to show you our action plan in Refining & Marketing, which will shortly return us to profitability.

We expect only limited improvement in this scenario. European demand will be stable, with decreasing consumption of gasolines, offset by growing demand for gas oils. In terms of capacity, tightening product quality regulations will put the weaker refineries under pressure. A reduction of 1.5 million barrels a day by 2012 has already been announced in Europe.

Despite the expected reduction, however, in Europe and the Mediterranean area, we remain long. These drivers underpin a modest recovery in our TRC Brent refining margins, which we expect to reach USD$4.00 per barrel in 2014. Meanwhile, we expect the differentials between light and heavy crudes, as will be -- as between the diesel and fuel oil to reopen, benefiting our complex refining system.

In this scenario, we are committed to recovering profitability. In Refining, we will focus on increasing operational efficiency, through energy saving, streamline logistics, and fixed cost reductions. Meanwhile, the integration of our refinery system will see Gela Refinery processing residues from Taranto as feedstock. This will cut the production of low value fuel oil and the supply costs.

We will also benefit from the startup of our EST plan in Sannazzaro, which will enable us to fully exploit our deep conversion propriety technology, Eni Slurry Technology, EST.

In Marketing, we will continue our network upgrading program, improving the quality and the range of our offer, and developing oil activities under the Eni brand.

Overall, we will deliver over EUR200 million of additional cost saving by 2014, after which, already in 2011, mainly labor and energy costs. This action mean that even assuming a (inaudible) scenario recovery from 2010, we will reach the (inaudible) this year, and grow our EBIT EUR200 million by 2014.

We plan to invest about EUR2.9 billion, in line with the previous plan, focusing CapEx on low risk and high return projects. About 70% of the spending is on Refining. The main projects are the EST plant in Sannazzaro, which will become a zero fuel oil refining and logistic systems.

Marketing accounts for 50% of the CapEx, mainly rebranding non-oil development.

Thank you for your attention. Sandro will now take you through the financial outlook.

Good afternoon, ladies and gentlemen. Today, I will take you through our progress and targets with regards to efficiency. I will also detail our cash allocation priorities, and that our planned scenario of USD$70 per barrel oil, the cash flow generated over the next four years will be sufficient to maintain a strong balance sheet, fund our attractive CapEx program, and thus, to guarantee stable cash returns through our dividends.

Efficiency will continue to be an important part of our strategy. Since the beginning of the program in 2006, we have delivered over EUR2.4 billion in cost saving by streamlining our processes and driving continuous improvement in our operations. Savings achieved in 2010 amounted to over EUR540 million, half of which came from enhanced efficiency at corporate level.

Our new plan in (inaudible) is a step up in our efficiency drive. We are targeting EUR4.1 billion in total savings for the 2006-2014 period. Overall, including the savings achieved since 2004, by the end of the plan period, we will have taken EUR4.4 billion of costs out of the business.

This will be achieved through procurement optimization, further streamlining our logistics and of our Downstream operations, as well as increased labor efficiencies.

Maintaining a strong balance sheet is one of our key priorities. [Dispersals] of EUR2 billion expected in 2011 and growing cash flows from operations during the plan period will progressively reduce our net debt to equity ratio to below 40% by 2014.

Meanwhile, our current net financial debt of EUR26 billion is associated with low risk activities. Around EUR10 billion belong entirely to Snam Reta Gas, which has a stable and solid cash flow that covers its investment needs and contributes to lower the risk profile of the entire Eni's portfolio.

EUR3 billion of consolidated debt are attributable to Saipem, whose major ongoing investment program relating to offshore drilling and construction will be completed by the end of the year. The cash flow generated by the new vessels, as well as the cash flow expected from the existing backlog, the highest in the Saipem's history, will positively contribute to the Group financial position.

Finally, EUR13 billion are attributable to Eni, and mainly linked to development projects under PSAs that have a safe and quick payback period.

Our net financial debt of EUR26 billion is well diversified by source of funding, and it is characterized by an optimal profile in terms of both composition and duration. More than 50% of our total net debt has a maturity of more than four years, and bears fixed interest rates.

In 2010, we have successfully placed bonds with an average maturity of over seven years, which have contributed to widen our investment base, and extended the average maturity date of the long term portion of our debt to around six years.

Throughout the plan, our target is to maintain the same structure so as to match as much as possible the length of the funding with the timing of development of the most important Upstream projects.

Our CapEx for the 2011-2014 period, though broadly in line with the previous plan, will be even more focused on E&P, with well over 70% of expenditures dedicated to Upstream activities. Chief among these will be the development of giant projects such as Zubaire, Junin, Perla, Goliat, and Kashagan. Other important investments include the completion of the EST project at the Sannazzaro refinery that will significantly increase the plant's conversion capacity and the renewal of Saipem's fleet.

In 2011, CapEx will be in line with '10, and will amount to roughly EUR14 billion.

Our dividend policy remains unchanged. We have announced that we will propose a full year dividend of EUR1.00 per share for 2010, and will grow this in line with inflation starting from 2011.

Thank you for your attention, and I will now hand you over to Paulo for his closing remarks.

Thank you, Sandro. In summary -- in summary, we are now entering into a highly productive phase of our growth, and the plan we have outlined today reflects this. Eni will, over the next four years, deliver value through leveraging the quality, breadth and depth of our asset base, our giant projects and our integrated business model.

Our E&P division is well positioned to be the engine of our growth. The investments we have made are entering to production, and we see an acceleration of that growth from 2012 onwards.

Confidence in our growth projections is underpinned by the progress we have made on giant projects in Iraq, Venezuela, Angola, and Russia. In Gas & Power, we are taking action to tackle the tough market environment, and are well placed to benefit from a recovery in the medium term. We have a very positive view of the European gas market in the longer term, and we believe that our infrastructure based businesses and consolidated position will continue to deliver solid and stable profits.

So to conclude, Eni is now entering into a new phase of growth. The investments we have made are set to deliver industry-leading E&P production growth over the next four years. This highly attractive E&P portfolio, coupled with our leadership in the European gas market, positions us well for the challenges and opportunities we will face in the global energy market over the next four years.

Thank you for your attention. I will now ask Camilla to moderate the Q&A session. Camilla?

Hello, everybody. Thank you. We shall start the Q&A session with some questions from the floor. Can I remind you please to stand up and state your name and company before you ask your question?

Stand up?

Well, if you could.

It's Iain Reid from Jefferies. I've got a couple questions on production, and one on Snam Rete Gas. Looking at the chart, it looks like your production is going to be fairly flat in 2011. Is that ex- or including any Libya effect? And just to be clear on what Paulo said earlier, did you say that for every 100,000 -- sorry, for every 100 days of the current situation in Libya, you're to lose 50,000 barrels a day of annual production? Is that what you said? Okay, thanks very much.

And just on Snam Rete Gas. I just wondered, you know, you say you can dispose of it if you want to. Do you want to dispose of it? Or does the Italian government stop you disposing of it? So can you just explain your, or Eni's strategy behind this?

Maybe I will ask Claudio to make a quick comment on 2011 growth. In any case, our growth in 2011, whatever it is, is excluding the Libyan effect, because -- just to be very clear on this point you made, suppose that we were to stay at this production level for 200 days rather than 100 days. This would be 100,000 barrels a day for the full year, that is, instead of making, I don't know, 1.8 million, we would make it 1.7 million, and just to be clear on that.

And I don't know if you want to add something on 2011? It would be a growth year, excluding Libya.

Yes, yes, I think that you said everything. The growth that we expected from our production 2011 was, because now we have Libya, more about 1%, around more than 1%, and that's, as Paulo said, didn't include Libya. Now we are to see what is happening in the future.

I think that if that lasts for -- what we are doing, what I can say what we are doing, we are studying some possible reactions to recover some barrels from -- especially, anticipating some production optimization activities on some fields where we operate, where we can very rapidly increase production. So if for -- if Libya effect lasts for next two, three months, maybe we can't recover some part of this production. If it lasts all year, it's not possible at all.

Okay, now let me move quickly to this Snam Rete Gas saga, no? Because we have been talking about Snam Rete Gas for so many years, and for so long. And let me just take a small satisfaction in saying that our resistance on this has been in the interest of our shareholders. Now, if we had sold Snam Rete Gas three years ago, four years ago, five years ago, last year, we would have made a mistake in the interest of our shareholders. This investment has been extremely good for all of us.

Now, when we look ahead, what I really wanted to avoid at all price was to be obliged to sell. Because when you are obliged to sell, in fact, you are obliged to sell at poor conditions, at the end of the day. You have to sell.

Now, today, we are free to choose what we want to do. We are free up to a certain limit, because, as you certainly know, there is a golden share, how much [valid] nobody knows, but let's say it is valid. And the Italian government can stop the sale of this strategic asset to a -- let's say, a buyer that they don't want to be the owner. But this does not mean we cannot find a potential buyer.

So our view is, if we find an opportunity to create additional value, that is, not to sell at market price, but with a premium on that, to a buyer that the Italian government would accept, then we would consider. If we don't find it, we keep this investment, which has been very generous in the last few years.

Is this --

(inaudible question - microphone inaccessible)?

No, we -- look, the third directive on gas has been applied a week ago, and we have been somewhat busy with Libya lately, but we've been looking at the future of this Snam Rete Gas stake in the future.

Go ahead.

Hi, James Hubbard from Morgan Stanley. Two questions, please. Sorry, James Hubbard from Morgan Stanley, for the record.

The ABCM have lost Greenstream gas. Have you, Eni, replaced all of that from other sources, or has the market gone and replaced part of that? And does the loss of that ABCM, do you see that visibly improving the situation in the near term for your business, your gas marketing operations there, temporary though that may be?

And then the second question, on China. You mentioned the MOU for shale gas. I mean, I understand there's a huge residential and industrial, commercial demand growth story there for gas. What are the key milestones we should be looking at, looking for you to deliver, to lead to something commercial, and what's the scale of the upside that you see for Chinese shale gas for Eni?

On the first question, I would tell you what is my feeling. Maybe Domenico can add something. But in principle, ABCM is so small, in terms of our European market and the (inaudible) market that we had no problem in replacing those sales. And the market has not been really affected by the lack of the Libyan gas in the market. I don't know if you would agree with me?

(inaudible) which the gas stopped flowing, we informed our clients that we could deliver gas to them in other points.

And we had no real problem. What is true, but this has nothing to do with Libya, I think, that there has been a convergence between spot gas prices and long-term oil linked contracts in the last few months, that was even unexpected by us, this quick convergence. We always thought that there was going to be a convergence, but the convergence has been quicker than we were expecting.

Now, on China, Claudio --

Yes, and talking about China and asset and time to market, when we can start producing, if I understood your question, we have six months in front of us with CNPC to select assets, and the selection of assets is also based on what we can swap with them on the Africa side. As you know, this MOU implied that reciprocity between us and CNPC, Africa, and against China, after the six months that we have selected these assets, the time to market in shale gas, in this very new play, very new basin, we expect about three years. And the amount, the growing -- the growing of this gas, because we are not the only one. There are other three -- at least two, three majors that are there.

The expectation that they have is to have some big improvement in the next four, five years. That's what they expect to show by 2015, 2016, to have some big contribution by the domestic production.

Yes, hi, it's Jon Rigby from UBS. A few questions. First, on Galp, and you mentioned the sort of guiding principle about your disposal process, if it were to be one at Snam, would Galp be the same, that it would only be sold if you could achieve a price higher than the market price?

The second is on CapEx, the E&P CapEx. I notice you're now sort of extending to a period where two years, you've got Kashagan in two years, you're probably not spending so much money on Kashagan, given the startup date. Yet the CapEx number has gone up for the four year period.

So I just wondered what the moving parts were, if you could go back through that a little bit. And effectively, does it imply you're saying that the growth rate beyond 2014 actually continues to pick up, that with the implication of additional investment?

And just one last thing on Perla and Junin. They're quite unusual, particularly Perla, and I understand you're quite close, or have reached agreement on gas pricing. So could you sort of at least indicate where you think the rates of return on Perla sit within the portfolio of new projects? Thanks.

On Galp, a quick answer. Yes, we expect some premium for a co-controlling stake, probably based on the last three months' share price. So a formula which will recognize the fact that we are co-controlling the company. Not a huge premium, but some premium, yes. Otherwise, we keep it.

Finally, we went close to a deal one year ago. If we had made this deal one year ago, we would have left on the table some value, and we think, really, that Galp can show additional value in the near future.

Now, on the E&P CapEx and Perla, Claudio?

Kashagan?

Yes.

So first Kashagan, and our -- versus our budget. In this budget, we have just a few money on Kashagan, Phase 2, just for the feed and for the [conceptual]. As you know, we are revising -- not Eni, but the consortium, and Shell is the leader. We are revising this [copper work]. So we don't think that in the next four year plan, we have huge investment on Kashagan Phase 2, so I don't think that we're going to have this problem. And to increase CapEx, I mean.

And for Perla, it is true, we are close to finalize our GSA, and we can say that Perla is in the range, is not diluting our average internal rate of return. So it's in the range of our -- our average internal rate of return, as we said before. So it's a good project.

Hi, Alejandro Demichelis from Merrill Lynch. I had two questions. The first one is on Galp, and the EUR2 billion divestment that you're talking about. What would be the use of that cash going forward?

And the second question is on the MOU with Petrochina. Maybe you can give us some kind of indication in terms of size where this money was, or reserve production that you're willing to put into the MOU?

On the first question, you are talking about the EUR2 billion of divestments we are going to make in 2011?

Yes, that's correct.

A large part of this would be forced sale of international pipelines. We'll use it to reduce debt. Essentially, we have no project in the pipeline for investment, for -- let's say, investments, acquisitions, or major moves, apart from the CapEx we have announced.

On the second question --

I'm sorry. For Galp, if you would, you get -- what are the --

Now, if we are for Galp, this will move our debt to equity ratio very quickly below 40%, and probably much below 40%. And at that point, we might review what is on our radar screen as potential opportunities.

Okay, thank you.

(Inaudible), the MOU is, you know, as I said, we are going to select the assets in the next six months, so I can give you a broad indication about the expenditure for this project, but just about the exploration phase, not the development phase, because we have to select the asset before we put in the plan some -- between USD$50 million, USD$70 million, USD$80 million for exploration. That means seismic and stratographic wells. And that is one side of the MOU.

The other side is in Africa, where we have blocks 100%, and so we are operator. We're going to reduce [for] amount to CNPC, so on the other side, we're going to reduce costs.

Hello, it's Irene Himona, Societe Generale. I had two questions, please. First, you give us your dividend policy at your USD$70 oil price. Could you say a little bit about the priorities of the financial policy should the environment remain at the current USD$100 level? How should we think of it? Do you repay debt first, or does the dividend policy change?

My second question, on Galp, should you retain that stake, and should the Company require a capital increase to finance Brazil, for example, would you participate? Would you be diluted? Thank you.

First on Galp. I mean, we act within the governance of Galp in such a way to avoid a capital increase to finance the investments in Brazil. If -- well, I think in the unlikely event that it would be needed, an increase in capital, in principal, we would be part of it, because we could not dilute our stake, which will imply a change in the governance. But I consider this a very unlikely possibility.

Now, as far as our dividend policy is concerned, you might remember that we defined our dividend policy as something which is sustainable for the four year plans. So if we would think that the oil price for a long period of time would be USD$100, and this would be reflected in our plans, of course, we'll change our dividend policy to take into account this new number.

For the time being -- well, I have to tell you that this number of USD$70 might seem a little obsolete, in a world which is talking about USD$110, USD$120, I don't know how much it is today. That's true. But it is also true that we are living through strange times for the oil price. We personally -- we think that there is at least a USD$15 oil price today which is due to North African unrest, that is not really reflected in demand and offer.

So we still have time in front of us, because we will announce our dividend for 2011 at the end of July, and we hope that by that time, the world will be more clear what it is today.

Just to make (inaudible). We -- I believe that we are ready to change the dividend base, not the dividend policy. The policy is -- which I believe there is room to maintain a (inaudible), is to increase the dividend base with the inflation, registering the OECD countries.

Of course, in case the price of the barrel will be higher than the USD$70 we have utilized, that could be the possibility to review the dividend base.

Dividend base, not dividend policy. Did I say dividend policy?

Exactly. (laughter)

Ah, okay. No, mistake. Dividend base, he is right.

There's another question from the floor, over there. May I just remind the people who are listening to us on a conference call that if they want to ask questions, they need to book themselves in, and then we will proceed to the conference call questions.

Thank you. Christine Tiscareno from S&P Equity Research. I read that you, OMV and a Chinese company have continued to do business with Libya buying oil, and you had said that the only way you would stop doing business with Libya is if the EU forcibly, legally asked you to. Could you clarify your policy, please?

Yes. Well, let's say, so far, our production of oil has been very small, since the conflict in Libya has exploded. And I think it will go to an end fairly soon. I am talking about days.

The question we are asking ourselves, and we ask also to the government, to our government, which is consulting with the European Union, is what should we do about domestic gas? Because domestic gas, which is the large part of our production today, is destined to the population, and we think that to stop this production would really create a problem to the population. And so far, we have been encouraged to do whatever we can to continue this production, because you know, this -- we are the only producing gas for electricity production in Libya.

We have been encouraged to continue, and we will continue to do so as long as we can assure safety to our people on the ground.

So it will have nothing to do with whether Mr. Gaddafi is still in power, whether -- whatever the political situation occurs in Libya?

No. The electricity is not for Mr. Gaddafi, it's for the Libyan people.

Thank you. I think we might take a couple of questions from the conference call now, before we come back to the floor.

(Operator instructions) The first question, from Mrs. Lucy Haskins from Barclays Capital. Mrs. Haskins, please.

Thank you, and thank you, gentlemen, for the presentation. Two questions, please. I think the cash breakeven has risen from USD$40 to USD$45 a barrel, and I wonder what you could tell me -- what the driver behind that increase was. And the second question was to find out what proportion of the 2014 production target is Iraqi volumes?

Okay. There's a second question? Do you have a third one, or not? Just two, okay. On the first one, Sandro.

Over the period, as already anticipated during the presentation, we expected that the growth in the production in E&P, and the disposal of some known core assets, included international pipelines, will make possible the decrease in our debt. But in terms -- in particular, the increase in the production will make possible associated with the efficiency that we are aiming in Refining, and in our Petrochemical business, it will make possible to have a breakeven in terms of cash flow at around USD$40 by the end of our plan period.

So, could I just interrupt? I was actually talking specifically about the economics of the Upstream production, which I think seems to have moved from USD$40 a barrel to USD$45 a barrel.

Yes, you're asking about why the breakeven. The breakeven of our project passed from USD$40 to USD$45 -- that is your question?

That's right.

Okay. So the answer. The answer is because we have bigger projects, different -- bigger projects, we are also in inflation, to pay (inaudible) 4% to 5% of increase, and there are more offshore projects on-stream.

Just to give you the proportion between our increase of production that -- for the new project, will be 2014, of 630,000 barrels per day, the Iraqi production will be about 110,000 barrels per day, and that production for sure, with other production, lead to the big offshore field in the Bering Sea and in Alaska, in the Gulf of Guinea, that will start production, increased the breakeven price.

The new projects, breakeven price, the offshore new project breakeven price, is about -- between USD$50 and USD$55 per barrel. So that is the reason.

Thank you, that's very helpful.

And Iraq, actually --

Done.

Next question, Mr. Jason Kenney from ING. Mr. Kenney, please.

Mr. Kenney, please.

Hi, there. Just a quick question on Russia, if I may. Obviously, a significant resource exposure through Severo Energia, and I note the recent progress with [gas sales] agreement with Gazprom. I just wondered if you could give us a bit of insight on the profiling for CapEx, and then, the ramp-up of production from Russia over the period to 2018. But I think you mentioned 120,000 barrels a day by that time.

No, first point, we don't have any big exposure with Russia, because we acquired 1.5 billion of 2P reserves, and our exposure at the moment is less than 600 million. For the future, it is true, when we start production, when we start investing, we'll increase our exposure, but also, we start the cash flow.

The contribution of Russia in the -- for the four year plan, at the end of the four year plan, will be about 50,000, 60,000 barrel per day oil equivalent equity, any equity. And we start the first development, Samburgskoye, early 2012. And we talk about EUR1 billion, for sure, of investment for the future. And we are going to start this year. And the full development of the four fields will finish -- they will be completed by 2017, 2018.

Are we talking single figure billions of CapEx?

Single figure billion, yes. Yes, we are talking about -- around EUR1 billion for development.

Fair enough. Thanks.

Can we have the next question from the call?

Next questions, from Mr. Sergio Molisani from UniCredit. Mr. Molisani, please.

Yes, good afternoon to everybody, and thanks for taking my question. Three questions, if I may, the first on slide 25. Looking at slide 11 of the Upstream seminar, can you give us also an idea of what is the present value per barrel of the P1 reserve, and not only the P2 reserve? And that's for the 2P reserve. If I remember well, on the occasion of the Upstream seminar, they didn't include the Junin 5 and Perla. Can you confirm that this is included in the new numbers or not?

Second question, on ForEx. Can you give us an idea of the ForEx assumption of your business plan and the difference compared to the previous plan? And the last question is on the free cash flow neutrality of the USD$40 per barrel in 2014. I struggle to reconcile these guidelines with my numbers.

So can you give us an idea of what's the cash flow per barrel that you expect in 2014, for your total Upstream performance, or worst case, for the new production? Thank you.

Okay, so I -- I start from the last one, that is the easier one. At USD$70 per barrel, our cash flow per barrel is about USD$24. So that is the number, it's USD$70 per barrel. At the USD$100 --

For the entire portfolio. For the entire portfolio.

Yes, that is average, for the portfolio.

Okay, thanks.

And if you go, if you jump at USD$100 a barrel, we reach a figure about USD$30 cash flow per barrel. That is the answer.

The second point, it is true, the figure that I presented in June, we didn't end on the P2 all the reserves of Junin 5 and parts of the (inaudible) and Perla. Now, we just have a part, a portion of that, as undeveloped reserves, linked to the early production of Junin 5. Perla is not yet inside, because we are going to sanction Perla, the pilot, the experimental phase of Perla this year. So there is no Perla. We have the experimental phase, the early production phase of Junin 5, and we have the rehabilitation plan of Zubaire. And we can talk about 200 million barrels for -- altogether, for the experimental phases.

And ForEx is Sandro.

And as far as ForEx assumption is concerned, we have maintained a flat exchange rate of USD$1.3 per EUR1.00 over the entire four year plan.

Thank you.

Thank you very much.

Is there any -- are there any more questions from the room? One more?

Good afternoon. Andreas Cowrie from MediaBank. My questions refers to take-or-pay contracts, and if I remember well, you provided an indication of EUR1 billion cash burn in 2010. I would like to know if you can give us an indication of potential breakeven or slight cash burn on the back of the renegotiation of the take-or-pay contracts that you are experiencing now. Thanks.

Let me just give you this quick answer. Without any renegotiations, so it goes -- the world goes on like it is today, we would expect a much lower number in 2011 as compared to 2010, everything being equal. If, to all that, you add Libya, then we might go to zero, to a number not too far from zero. Depends, of course, what happens in Libya.

Then, on the negotiation, we will see, because the negotiation is ongoing, and it's very difficult to tell you what will happen on the take-or-pay prepayment.

Thank you. It's Neill Morton from Berenberg. As a question for Mr. Scaroni, I don't wish to make this sound like a job interview. But if you are reelected this year to a third term, what would you like to do differently, versus your tenure hitherto? Thank you.

This is a -- this will require a long answer, a really long answer. Let's say, in terms of my decisions, not much difference, I have to tell you. I still think that what characterized Eni is to be an integrated company, integrated in the sense of oil and gas, which is our peculiarity. And then, second, that we are a growth company. We are the only one large international oil company which is actually growing through our business, let's say, without major acquisitions, but simply growing.

We have in front of us a period of growth, and which will go -- which will happen in the plan. But our growth will continue beyond the plan, and I will -- I would use the next three years to make sure that our growth continue for the whole decade.

Okay. If there are no more questions -- there are no more questions from the room, I take it. I think there are no more questions from the conference call. So our strategy presentation is now over. Thank you very much, ladies and gentlemen.