埃尼石油 (E) 2009 Q4 法說會逐字稿

Ladies and gentlemen, welcome to our 2010 strategy presentation. I am particularly proud of the fact that Eni has over the last five years been the fastest growing of all the major international oil companies. Our production has increased from 1.6m barrels a day to 1.8m barrels day, a growth of 1.7% a year against a net decline reported by our peer group over the same period.

Today I will focus on what underpins the success and what we will be doing to ensure that our outperformance continues over the next four years. We have a distinctive and unique set of assets and we have therefore pursued a deliberately differentiated strategy from our peers.

In 2005, when I took over as CEO, most of our peers were focused mainly on oil and gas, had larger, much larger refining businesses than Eni and were pursuing very popular investment projects such as Canadian tar sands. Some market commentators at that time felt that to succeed we should emulate some of these larger peers through divestments of some significant parts of our businesses such as Snam Rete Gas and Saipem, building a larger refining capacity and investing as well in Canadian tar sands projects.

We felt that our differences could in fact become our strengths. Our plan was clear, we wanted to build our production organically and through selected acquisitions in areas that we knew and which had an attractive E&P potential. We believed then, as we continue to believe today, that our gas presence in Europe was a strategic differentiator which should be invested in and we would continue to limit and rationalize our refining capacity.

After five years what we achieved were first an enhanced E&P portfolio made up of highly attractive, large scale, low cost oil and gas resources. We have maintained best in class lifting costs per barrel, extending our leadership on costs every year. This has been driven by increased operatorship, we operate an additional 300,000 barrels per day, bringing our total operated production to 2.5m barrels per day. Our growing exposure to giant fields and our great focus on low cost legacy countries and our strengthened resource base of 30b boe, 10b more than in 2004, will provide a powerful platform for our growth.

Secondly, we have successfully transformed Gas & Power from a local Italian player to a truly European market leader. In 2004, when we were the first stage of evolution from the former Italian gas monopoly, Italy accounted for around 70% of our sales. Today, we are the European leader with a European market share of 21%. International sales have doubled and Italy now accounts for under 40% of our sales. This transformation has also been delivered profitably. Our EBITDA has grown by an average of over 2% a year since 2004.

Our regulated businesses have meanwhile performed very well as we expected. Our decision to maintain our shareholding in these assets has been extremely rewarding, delivering a total shareholder return in the five year period in excess of 65%. We remain confident it will create further value in the near future.

Turning to Engineering & Construction, Saipem remains a core part of our strategy. By merging it with Snamprogetti in 2006 we have created in Saipem a leading player which has more than doubled sales and tripled profits to become the recognized world leader in oil services. In the last five years Saipem has delivered a shareholder return of 210%.

But, our strategy has not been just about growth. In refining and petrochemicals, where our capital employed was 16% in 2004, about one-third of our peers, we have worked to become even smaller and we are now at 13%. And on cost efficiency too we have delivered impressive results, saving up to EUR1.6b. In relative terms this makes an outstanding result. So, we are proud to be different and we aim to continue to build on these distinctive qualities as we move forward.

Over the next four years Eni will continue to pursue growth, leveraging on its unique integrated model. Within E&P our existing asset base provides a strong platform for growth among our peers and we will continue to look for ways to enhance this. The industry challenges over the next four years will be securing access to resources and executing increasingly complex projects. In this context, our strengthened portfolio and our strong pipeline of giant projects will drive growth while our integration with Gas & Power will contribute to provide access to fresh resources in the most attractive regions for oil globally.

In Gas & Power we will continue to leverage on our highly attractive leading European position. We expect to see gas demand recovering from its current lows and long term consumption growing. Gas is the cleanest fossil fuel and will be increasingly used to combine economic development with environmental protection. As the European leader, we are ideally placed to benefit from this growing market.

And in Refining, weak trading conditions will continue. In this context, we see our small exposure as an advantage. We will cope with this challenging environment by improving our cost position while continuing to keep tight control over capital employed.

Three operational elements will underpin our strategy over the plan period. First, we will continue to look for ways to integrate our assets, in particular, between E&P and Gas & Power. Second, we will continue to drive forwards our efficiency program and this plan sets out some new targets that will contribute to our future profitability. And third, we will continue to be financially disciplined, focusing on growing profitably and operating within our own investment guidelines.

So, let me now speak more specifically about each of our businesses and the targets that we are setting here today.

In E&P, we will build on our strengthened resource base of 30b boe and our ability to access major resources in Africa, Venezuela and the Caspian region, to deliver average annual organic growth of more than 2.5% during the plan period and above 2% between 2013 and 2016. We will continue to focus on growing production from giant projects which will contribute an additional 400,000 barrels a day in 2013. And extending our operatorship by 2013 we will operate 4m boe per day, an increase of 1.5 boe per day compared to today and roughly double our operator production in 2004. This will consolidate our industry leading position on costs and further strengthen our capture ratio with new production breaking even at around $40 a barrel enabling us to benefit from any further upside in the oil price.

Turning now to Gas & Power, we will add 14b cubic meter of sales by the end of 2013, growing our overall sales from 104b to 118b cubic meters. We will strengthen our European leadership by leveraging on our scale, long term and diverse supply sources, including contracts which we have recently and favorably renegotiated, and the trading capabilities consolidated through the Distrigas acquisition.

Our regulated businesses recently regrouped in Snam Rete Gas will fully harvest the synergies from integration. They will also deliver value from new investments in transport and storage assets, which enjoy guaranteed returns with a premium on new investments. The combination of the resilience of our marketing activities and the steady growth of regulated businesses will enable us to maintain solid profits of EUR4.4b a year despite the announced sale of the TAG, TENP, and Transitgas pipelines by the end of 2010.

And in Refining, we see weak trading conditions continuing, in particular, in terms of low refining margins, although we are beginning to see a reopening of the light heavy crude spread. We will cope with this challenging environment by improving our cost position and enhancing flexibility of supply at our main refineries.

In Marketing, we will continue to strengthen our central European position. In Italy, we aim to leverage on the rebranding, restyling, of our network to deliver a market share increase of over 2 percentage points to 34% by 2013.

As a result of all these actions, our R&M will be cash positive by 2012 even under our bearish market scenario.

That's our strategic focus and our targets for the next four years. Let me now hand over to each of our business heads in turn who will provide more detail on the plan within each of their business areas. Claudio.

Thank you, Paolo. Good afternoon, ladies and gentlemen. 2009 was a year of significant achievement in E&P. In a challenging year of the industry we enhanced the strategic value of our portfolio and strengthened the foundation of our future growth. We added three new giant projects, Junin 5, Perla and Zubair, with a reserve potential for Eni of more than 1.5b barrels and up to 180,000 barrels per day of extended petrol production. In addition, we deliver all 27 of the startups planned for 2009. Ramp up from these fields, which have a combined expected production of 190,000 barrels per day, will further support our future growth.

During 2009, we also took three major FIDs, Goliat, the first oil development in the Barents Sea, for which we have already obtained governmental approval, and in Algeria, El Merk and MLE, the first development which comes from the acquisition of First Calgary. These fields will produce around 90,000 barrels per day at peak, mostly oil, and contributes about 140m of 2P reserves.

Exploration has long been a key driver of our strategy. In 2009 we discover over 1b barrel of resources at an industry leading unit exploration cost of $1.8 per barrel. Finally, our low cost structure enable us to deliver industry leading cash flow per barrel.

Our access to giant projects and exploration success have all contributed to strengthening our resource base, a long term strategic objective for Eni. In the last five years we added 10b barrels to reach a total of 30b barrels, extending our resources life index by more than 10 years to 46 years. These resources are largely related to conventional and low cost plays. Exploration has played a major role in this strategy. Over the last five years we discovered 5b barrels, many of which we fast tracked to production.

Last year was particularly rewarding. Perla was our top strike but we also achieved very good results in Ghana which we entered in 2009, Angola and Gulf of Mexico. We estimate recent exploration will contribute 170,000 barrels per day to our 2013 production. In 2009 we also entered new unconventional plays, gas shales in the US, and a large CDM development in Indonesia.

Our strengthened resource base is one of the drivers of our performance going forward. The other is our leadership in terms of efficiency and cash flow per barrel. We have long been best in class on this front and expect this trend to continue in the future, enabling us to deliver maximum value as we turn reserves into production. Our leadership on cost is driven by our focused presence in core legacy area which provides low lifting cost and synergies. It is worth highlighting that at similar Brent conditions the two last cash flow averages are in line despite the severe cost inflation and depressed gas price of last year. Our strengthened resource base and our industry leading cost mean we are well placed to deliver profitable growth.

Our goals will be achieved through more production, more giants, and more operatorship. I will now take you through our targets in more detail.

The two pillars of our growth strategy are the low depletion rates of our producing fields and our strong pipeline of project startups. This will drive an average organic production growth of above 2.5% per year between 2010 and 2013, based on our scenario of $65 per barrel. 2010 production will be in line with that of 2009, assuming the same level of OPEC cap and the planned disposal. Furthermore, our giant projects will enable us to keep an annual growth rate above 2% beyond the plan.

We have one of the lowest depletion rates in the industry for two main reasons. Our exposure to Africa where much of our production comes from giant fields and where we are able to seize expansion opportunities which normally follow the first phase of development of these fields. And, our reservoir management capabilities that enable us to fight natural depletions across the world, and particularly in mature areas, through effective production optimization activities. 50% of our production today comes from giant fields, most of which are still in very early phases, with large remaining potential, and continue to contribute to the stability of our production platform.

We will build on this stable platform with our strong pipeline of startups. Over the plan period we will deliver 41 startups, distributed between OECD and non-OECD countries. This will contribute around 560,000 barrels per day by 2013. 50% of this will come from projects which have already reached FID, rising to 90% if you include FID schedules in 2010. 16 of the new startups will be related to giant fields. These long lasting projects where Eni has a material stake represent 70% of new production.

Let's take a closer look at them. These are the giant projects which will ensure stable contribution to Eni production for most of the decade and provide the basis for our growth. By 2013 their contribution will be around 400,000 barrels per day. Some of them derive from our recent exploration success, such as Perla and Block 15/06, and the majority are operated by Eni. In particular, I would like to focus on the new projects in Iraq and Venezuela.

We selected Zubair because of its huge potential, its conventional and straightforward technical development requirements, and the fast ramp-up of production. The field development will take place in two phases. The rehabilitation plan, which will improve the existing production rate and allow us to gain full knowledge of the reservoir, and the redevelopment plan which will increase production to the 1.2m barrels per day target. Based on this plan, equity production will reach 120,000 barrels per day in 2013. In order to achieve this target a real integration with local of communities aimed at the development of the area will be a crucial component of our strategy.

Let's turn now to Venezuela. The country's resource potential is huge and Eni has gained access to two major opportunities through exploration and business development. Two years ago when we started to evaluate development options for Junin 5 with PDVSA, one of the main constraints was availability of natural gas. The discovery of Perla changed the scenario. We now plan an integrated development which will exploit the synergies between the two fields. We will use gas from Perla to upgrade the heavy oil of Junin 5.

Junin 5 will be developed in two phases, the early production of 75,000 barrels per day and a full production development with a plateau of 240,000 barrels per day. The gross reserves are in excess of 2.5b barrels. The (inaudible) of Perla, the largest gas discovery in South America, is progressing very well. We currently estimate reserve potential in excess of 8 TCF, but this number might grow even further. We are fast tracking the development of the field, targeting early production in 2013 of 300m standard cubic feet per day. These three giants will deliver a combined equity plateau of up to 180,000 per day in the mid long term, supporting the growth target of our plan as well as growth beyond 2013.

Our production growth will also be characterized by increased operatorship. We will add 1.5m barrels per day of operated production by 2013, reaching 4m barrels per day. Increased operatorship will give us more control over our equity production and the time to market of our projects and enable us to maximize synergies in our operation and improve the efficiency of our performance. By operating more fields we will continue to build on our strong Eni competencies and to invest in our human capital, the fundamental driver of our long term sustainable growth.

Our long term growth strategy over the plan and beyond will be supported by a EUR37b CapEx program, of which EUR10.5b will be invested in 2010. The EUR4b increase compared to the previous plan is due to new projects in Iraq, Venezuela and other countries for EUR5b, the re-phasing of gas projects resulting in a reduction of EUR2b, and an additional increase of EUR1b due to changed market conditions in terms of cost inflation and exchange rate. Over 40% of the development CapEx will be spent on projects whose peak production will fall beyond 2013. Exploration expenses will be reduced by 14% versus the previous plan as a result of the absolute focus placed on the development of these reserves discovered in the last five years. In spite of this reduction, we will grow our total resource base with a replacement ratio of 120% for the period.

In conclusion, our strategy centered on production growth, increasing operatorship, and focus on giant projects is continuing to enhance the value of our business. Our portfolio is resistant to potential market downturns while being exposed to material upsides under high price scenarios. Our new production has an average breakeven price of around $40. At a Brent price of $80 the value of these new barrels increases by over $6b, enabling us to capture the upside of positive market trends and maximize the value of our production. Our future is solid and based on visible pipeline on new giant fields that will allow us to grow production and build on the value of our existing portfolio.

I now will hand you over to Domenico.

Thank you, Claudio. Ladies and gentlemen, we are now going to speak of this fascinating Gas & Power division, so please wake up a little bit.

In 2009, we leveraged on our leading position in European gas market to grow profits despite the very challenging environment. The economic crisis caused the gas demand to decline worldwide, especially in the power generation industrial sectors. Furthermore, the growing production of unconventional gas in North America caused a diversion of LNG to Europe further enlarging the oversupply in this market. As a consequence, spot gas prices decoupled from oil prices and therefore for the price of long term contracts, which are largely linked to oil prices. The liquidity of the spot gas markets increased strongly making spot gas a more credible sourcing option.

Notwithstanding the context, Eni posted EUR4.4b of EBITDA, confirming its excellent profitability, in particular, in the market segment to benefit from an integration with Distrigas and the contribution from power generation.

Looking ahead, we expect the gas market to recover from its current low reaching 2008 levels by 2013. Beyond 2013 demand will continue to grow and gas will remain the fuel of choice in a low carbon world. It's globally available, potential reserves are abundant, and it's the cleanest fossil fuel. Within this context, 2010 is the most challenging year in the plan period. The recovery of gas demand will be in its early stages and European hub prices will remain low. Meanwhile, we expect the competitive pressure in Italy to continue as new import infrastructure come on stream. Gas demand will strengthen in the following years and by 2011 or 2012 spot gas and long term contract prices will recouple, a trend which is reflected in carbon to gas forward prices.

In the context of this future demand our large and diversified long term supply portfolio will remain a key asset, giving us available gas hub ability. Recent renegotiations with the producers have added a flexibility and price competitiveness to our portfolio, providing a solid foundation for sales and market share growth in the plan period.

Even in the context of low demand recovery and increased competitive pressure, our leading position in Europe and our large and [diversified] supply portfolio will enable us to grow sales and maintain profits. We target sales of 118 bcm in 2013 when we will supply more than 22% of European market, an increase of 14 bcm compared to 2009. Sales growth coupled with improved flexibility and efficiency will mitigate the impact of tighter competitive scenario and drive solid, stable EBITDA of EUR4.4b a year on average, despite the sale of TAG, TENP and Transitgas that in 2009 contributed for EUR200m. This growth will be driven by the increase of our international sales and the preservation of our leading position in Italy.

In Europe, excluding Italy, we target sales of 59 bcm in 2013, a 6% growth a year over the next four years increasing our market share from 12% to 14%. This will be driven by the increased competitiveness of our portfolio, our multi-country approach in marketing, and by the further strengthening of our sales force in key markets, in particular, France, Germany and Benelux. I'm pleased to say that we have achieved significant benefit for the ongoing construction of a fully integrated approach to the market with Distrigas.

In Italy, our target is to maintain market share and to defend the profitability in the context of weak demand and increased competition. We will achieve this by taking up new offer structures that fully match the diversified requirement of our customers, especially for the business segments. In the retail market we will adopt an approach tailored on local specific conditions, leveraging on the capability of our sales force. The combined offer of gas and power is a valuable strength of our portfolio and we will leverage on the dual fuel offer to drive sales to both business and retail customers.

Operational efficiency will remain the core focus. We will further reduce our cost to serve the full range of clients by more than 20% and we will optimize our operating and maintenance costs in power generation.

Our performance in the next four years will be supported by EUR8.3b of CapEx. Just under 80% of this will be invested in the regulated business with guaranteed returns. The remaining EUR1.8b will be dedicated, EUR700m to complete an investment program in power generation and, in particular, to improve the flexibility of our plants and EUR1.1b to the merchant activities abroad, including the development of a storage capacity in Europe, a project that will provide G&P with a large flexibility of supply to support its international expansion program.

Thank you, and now I will hand over to Angelo.

Thank you, Domenico. Good afternoon, ladies and gentlemen. Let's start -- a look to last horrible year's results. In effect, in 2009 R&M posted the worst results in the history of the business. This is due to an unprecedented market scenario. In fact, at constant scenario, our operating profits grew by 7% driven by a robust performance in marketing with a 1 percentage point increase of our Italian market share to 31.5%, as well as our focus on headcounts and general cost reductions.

However, the business was affected by a double blow, TRC margin, more than halved compared to 2008, impacted our performance by EUR500m, and light heavy crude spread collapsed from $5.1 per barrel to $1.9 per barrel, due to the reduced availability of heavy crude oil in the Mediterranean. This impacted our performance by EUR408m.

Looking ahead, we expect the refining environment to continue to be challenging over the next two, three years. This is the result of lower demand affected by increasing energy efficiency and the use of biofuels, new refining capacity in the Middle and Far East and reduced export of gasoline to the US. In this context, we expect persisting weak refining margins although we are beginning to see a reopening of the light heavy crude spread.

In Refining, we will improve operational flexibility through a 15 percentage point increase of the share of spot crude supply, as well as through logistics and process optimization in order to select the most profitable slate to satisfy market needs. Furthermore, we will improve our middle distillate yield, achieving 43%, leveraging on the new hydrocracking units freshly started up in Sannazzaro and Taranto, and thanks to the EST plant in Sannazzaro whose startup is scheduled in 2012.

In Marketing, we will further grow our Italian market share to 34% through improvements in the quality and range of our offer, including non-oil activities and loyalty programs, as well as through the rebranding and restyling of our service stations. Internationally, we will continue to focus in Eastern and Central Europe, where we enjoy significant advantages in terms of supply, logistics, and brand awareness.

We have upgraded our efficiency program with a further cost reduction of EUR100m by 2013. Savings will be mainly concentrated on labor costs and refinery processes, including energy conservation. As a result of all these actions, R&M will be cash flow positive from 2012.

Overall, CapEx remains in line with the previous four year plan but with a different mix between marketing and refining. The relative weight of marketing has increased from 25% to 40%, as a result of the extensive rebranding of our retail network and the new LPG and new gas stations.

In Refining, around half of the CapEx will be invested in completing the EST plant, exploiting any proprietary technology, which will transform our Sannazzaro Refinery into a zero fuel oil refinery. A significant share of our program is devoted to flexibility enhancement through new sulfur treatment plants, hydrogen plants and logistics improvements that will enable us to differentiate our fixed stock slate and improve our yields.

I will now hand you over to Alessandro.

Thank you, Angelo, and good afternoon, ladies and gentlemen. Efficiency has long been a core focus of our strategy. We launched our efficiency program in 2006 in the context of a favorable trading environment, streamlining our processes and driving continuous improvement in our operations as a result. Since 2006 we have delivered EUR1.3b of savings, of which almost half came from Corporate, and we reduced the overall headcount by 3,400, 80% of total workforce in 2006.

In 2009 alone, we delivered cost savings of around EUR400m. There is still potential for further efficiency. In the four-year period we are targeting EUR1.1b of additional efficiency gains through technology improvement, commercial and supply optimization, as well as continuous process streamlining.

In 2010, CapEx will be broadly in line with 2009. Over the four-year plan CapEx will increase by EUR4b when compared to the previous CapEx plan. This is due to the new big contracts signed for the development of the Zubair and Junin 5 and Perla fields, confirming our focus on giant and fast-track projects that will secure long-term production.

Our net financial debt of EUR23b can be split into three parts. Around EUR10b belong entirely to Snam Rete Gas, which has a stable and solid cash flow that covers its investment needs and contributes to lower the risk profile of Eni's portfolio. The EUR3b net debt in Saipem are due to new drilling vessels and the FPSO units that will soon be in operation under long-term contracts. Saipem will generate a positive free cash flow starting from 2011. Finally, EUR10b are attributable to Eni and mainly linked to development project under PSAs that have a safe and quick payback period. Kashagan accounts for more than 50% of our exposure.

In 2010, we expect to maintain a net debt to equity ratio in line with 2009 while, going forward, the growing cash flow will progressively reduce this ratio to below 40%.

I now hand you over to Paolo for the dividend policy and the closing remarks.

Thank you, Alessandro. Before I conclude, I would like to state what will be our dividend policy going forward. Our oil price assumption is $65 a barrel for each of the four years between 2010 and 2013. Under this scenario we will maintain our dividend at EUR1 per share in 2010. Starting in 2011 we will grow our dividend in line with OECD inflation.

The energy industry as a whole faces continued challenges in 2010 and the macroeconomic climate, in particular, is uncertain. However, I hope you will see from what we have outlined today that Eni is well positioned, not just to weather these conditions, but to thrive in them over the short and medium term. Our continued growth in exploration and production is underpinned by a rich pipeline of giant projects, which gives us access to long-life, low-cost reserves. We will continue to have one of the most attractive production profiles in the industry.

Our leadership in European gas and power is a great business in itself, cash generative and resilient. This business gives us a fully integrated model which continues to prove a competitive advantage in growing our E&P business. Our distinctive and attractive asset base, coupled with our focus on efficiency, will enable us to continue to deliver significant value to our shareholders.

I will now open the floor to questions.

Good morning. Any questions from the floor? Irene Himona, there, please.

Thank you. It's Irene Himona at Exane BNP Paribas. You propose to invest 8% more, but for somewhat lower production growth than you were targeting last year, so the growth has gone from 3.5% to 2.5%. If we exclude the new barrels in Iraq and Venezuela, and using your $65 new price assumption, could you perhaps tell us how last year's 3.5% targeted growth develops in the new plan? Thank you.

I will hand the question to Claudio.

We can say that our target is based on 2009 production adjusted for OPEC cut that is 28,000 barrels per day. We have to remember also that due to the weak gas market condition we re-phased around 70,000 barrels per day by 2013, so just as assumption.

So looking at the new profile for the four-year plans we can say that, considering the 2.5% growth consider a contingency for the new project of more than 150,000 barrel per day. So, without contingency, our growth could be framed at the level of 3.6%. We put contingency because we are in a volatile situation, new projects, so the 2.5% is very resistant and absolutely achievable.

Any further questions?

Dear Mr. Scaroni, your fellow Board members, the other people present here and online, my name is Vincent Tange of Knight Vinke Asset Management and I have a question for you. Dear Mr. Scaroni, do you agree that your E&P business trades at a discount to, say, Total? And, if so, what will you do to narrow discount -- this discount? Thank you.

You are talking about the E&P business or the total business?

The E&P division.

The E&P division. Well, frankly, the calculation in terms of the sum of the parts is a complex calculation. I frankly don't why you say that ours trade at a discount as to Total. In any case, the reason for differential in calculation in the sum of the parts can be many. There are very many reasons. And normally, only time will tell if these differentials are justified or not. We are confident that in time and within the timeframe of our plan, our business, in total, and our E&P business in particular will be fairly valued by the market.

Thank you very much.

If there is no more question from the floor, then we can start with the conference call, please.

Ladies and gentlemen, the Q&A online is open. First question comes from Mr. Demichelis Alejandro from Merrill Lynch. Mr. Demichelis, please proceed with your question.

Yes, good afternoon, gentlemen. Alejandro Demichelis from Merrill Lynch. Two questions, if I may. The first one is maybe you can tell us how much gas you're expecting from Kashagan by 2013. And also, just to understand a bit better, how much of the growth that you're talking about is coming out of Venezuela?

And the second question is you are indicating that your new portfolio has a breakeven of around $40 a barrel. And I struggle there a bit to understand how the project of Junin breaks even at that kind of level.

Junin and --?

Well, mainly Junin. Junin and Perla.

Junin and Perla, okay. Well, I will hand over to Claudio for a few questions. The only one I can tell you right away is that Venezuela counts for relatively little within our plan.

At the end of the period 25,000 barrels per day --

25,000 barrels a day at the end for the period -- at the end of 2013. Kashagan, Claudio?

Kashagan, I can talk about the experimental phase that is the phase that we are running nowadays. So I think that we can confirm the target of 2012. The project has a progress of 72%, so in line with our budgeting, in line with our expectation.

And production in 2012.

And I confirm the production -- the first production by the end of 2012.

So -- how many barrels in 2013?

In 2013 we have approximately 300,000 as 100%. Gross production between 350,000 to 375,000 barrel per day production.

So, for us, will be around 50,000 barrels.

Yes, it's 50,000 2013, yes.

And the $40 as for Junin and Perla?

Yes, Junin and Perla, the breakeven on Junin and Perla is right between $45 and $50, so that is in the range of our -- of the breakeven of our giant projects.

And that assumes that the gas from Perla is used to upgrade the heavy oil, yes?

Well, maybe it's worth to explain a little bit how Junin will work because Junin will work in two phases. In the first phase there will be no upgrader and this will last for three or four years more.

Four years.

Four years. And the upgrader will start working only -- say, starting from 2014, 2015. So by that time Perla will be develop and we will be using the gas of Perla for the ugprader, while in the initial phase we will blend the bitumen of Junin 5 with fuel oil to make a blend which is sellable as it is. So no gas will be used for the first phase.

We can just add that we have a small -- we have early production on Perla, not for the upgrading, but just for domestic disposal in Venezuela at about 300m standard cubic feet per day by the end of the period as well.

This is Perla, yes.

Okay, that's clear. Thank you. So the $45 or $50 that you're talking about, does that include the upgrade or not?

That is include the full development, so also the upgrader.

Okay, thank you.

Thank you.

Next question.

The next question comes from Iain Reid from Macquarie. Mr. Reid, please proceed with your question.

Good afternoon, guys. I've got one question on the gas business and one -- a couple of questions on the production target. On gas you're targeting a growth rate of about 3% in terms of your overall volumes in Europe, which is about twice what you regard as the long-term European gas growth rate. Just interested in what the specific things you're going to do in order to reach that level of growth. Does it include, for instance, any acquisitions such as Distrigas in the plan?

And secondly on the production targets. I was a bit confused as to why you said you're re-phasing gas if you see that gas is going to recover over the next couple of years. Does that mean you've got a more gloomy view of gas over that period?

And, secondly, the significant amount of acquisitions you've made since 2007, I'm just wondering, of the 2013 target, how much of that is made up of those acquisitions. I'm thinking of Burren, Maurel & Prom, First Calgary, Dominion and Yukos. So what percentage of that is in the 2013?

Okay, let me answer first the general question around acquisitions and then I will ask Domenico and Claudio to go into the detail of your questions. First of all, all this plan, all the numbers we've been giving so far do not include acquisitions, any kind of acquisition, neither big nor small. More generally, our appetite for big acquisitions is zero. Our appetite for small, synergic acquisitions, similar to the ones you mentioned, so the Maurel & Prom or these kind of small things, is still there as long as they are synergic, they are under our financial discipline, they meet our financial requirements. And, generally speaking, for the time being, as far as we can see now, the pipeline is completely empty.

Now, having said that, I will ask Domenico to explain to you how this target of 3% volume increase will be reached.

It is true that these figures can look quite challenging and, in fact, they are challenging, but we are preparing for that. We are preparing concentrating our effort in the countries which we consider our target, namely France, Germany, Spain and [all these] and Benelux. We are making a big effort in our training activities. We are displacing the sales force all around Europe. So I would say look at the market, look at the activities we are doing. I think that the target we propose to you are achievable, with effort, but achievable.

First, the question about the gas. We don't -- I want to say that we didn't cancel any projects; we just postpone, we can say, LNG projects and the third phase of Karachaganak and just the postponement. And we are continuing with the Angola LNG and we are continuing but with a different speed on Brass LNG. And I said -- as I said before, these postponement has an impact of 74,000 barrel per day in term of production.

The acquisitions. By the end of the period, when we talk about our acquisition we talk about M'bundi, Burren, we talk about Russia, we'll have more or less 200,000 barrel per day in 2013 coming from our acquisitions.

Our acquisitions so far? The ones we have done --

No, I'm talking about the past --

In the past. Just to be clear.

-- because the question was on the past.

No, just to be clear. Okay.

Thanks. Could I just ask one more, sorry? Could you say also, Claudio, what the absolute amount of the contribution from Iraq is in 2013?

The contribution expected from Iraq is about 120,000 barrel per day by the end of the period.

Net to you? Net?

No, no. That is the contribution 2013, our equity production.

Okay.

Okay, thanks.

Next question comes from Mr. Colin Smith from ICAP. Mr. Smith, please proceed with your question.

Good afternoon, gentlemen. I've got two questions on gas. First of all, just looking at the CapEx of EUR8.3b for gas, 2% of that is in international transport which translates to something less than EUR200m. Now that doesn't look like it could possibly include any kind of expenditure for South Stream, which is obviously tens of billions of euros. So I wonder if you could comment on that.

And the second question was you just commented that you thought spot gas prices and long-term European gas prices would converge together. And I wondered if you could just explain why you thought that would be the case.

Okay, Domenico, can you answer on spot?

On spot in the --?

The first question was around CapEx, no? Your question was what are the EUR200m CapEx on international transport. This was your question?

The question was more it doesn't look nearly enough to include the value of an investment in South Stream. So it's really a question of what's the status of South Stream and how is that reflected in the CapEx plan.

You're talking about the South Stream. Oh, yes, excuse me, I -- no, it does not include South Stream. This CapEx plan does not include South Stream. So whatever will be spent before that date on South Stream should be -- well, it's another number.

As you probably know, let me just spend one minute on the South Stream. The South Stream will be a project run in the same way that we run Blue Stream, that is, we'll have an equity, the company which will make the investment of the South Stream, a limited equity, something like 10% or 20% or the total investment. The company will be self-financing off the books of Eni and, therefore, whatever will be spent there will be in the books of a company of which we will have a stake -- an equity stake but will not be consolidated in our debt. So that is the reason why South Stream is not included in these numbers we have been showing so far.

Now let's move into the second question.

Second question. Well, it's clear that today in Europe there is an oversupply situation. There is more gas than is needed and this comes from two facts. First, the decrease in demand that's a consequence of the crisis that we had in 2008 and 2009. We see some sign of recovery in recent months but, still, it will take a little bit of time before all the demand is recovered. On the other side, there are the large quantities of gas that are arriving from the fact the United States are not taking gas any more as the economic crisis had an impact on the Pacific area.

The consequence of this is that the prices -- the spot prices, the price of liquid hubs are still a -- I'm not talking a little bit, quite different from the traditional contract they have indexed to oil products. This situation will last probably for some months or some years after the end of this period, due to this -- the increase that we expect on demand and the fact that probably the consequence of the lower production of gas in Europe will take out some liquidity of the market. We see this difference between the price of long-term contracts indexed to oil and the price at the liquid market should decrease.

On the other side, what we are doing is to discuss and negotiate with our suppliers to adapt our contracts to this new reality. And this -- we are doing this, we have done with some producers, achieving what we intend to achieve, and we are continuing to do this with other suppliers.

Sorry, could I just come back on that? Because I don't think you quite said why you thought the spot and oil price linked contracts would come together. Because unless US gas prices are going to go up, won't they just carry on being arbitraged across the Atlantic at current levels and, therefore, significantly below oil price linked contracts?

No. The question, if I well understand, is that the US are not going to import any LNG and, therefore, LNG is going to be available at prices which have nothing to do with oil prices. Is this your question?

Yes, and that they are being arbitraged into European hub-based pricing and will continue to be so.

Well, you see, if I may try to give you an answer. First of all, you heard before that our gas projects, our LNG projects have been postponed. Well, many companies around the world are doing the same thing. The amount of LNG -- the increase of LNG in the world is going to go down and will not be material in the next few years. This, coupled with an increase in consumption, particularly in Pacific OECD countries, and China and India, will provide a destination for big quantities of LNG. This is the forecast we make.

There will be, of course, some LNG still coming into Europe, but we are talking about quantities which are not exceeding 15%, 20% of the European market, where, largely, the other 80% will continue to be supplied by piped gas linked to oil price. If this kind of -- the closing of the gap between spot gas prices made of LNG and the long-term contracts will not happen, then the long-term contracts will adapt to the new market conditions because they have to adapt. So on one side we believe that the two markets will get much closer than they are today but, if not, then there will be an adaptation of the contracts to make the piped gas, which is still 85% of the gas used in Europe, competitive.

Thank you.

Thank you.

The next question comes from Miss. Lucy Haskins from Barclays. Miss. Haskins, please proceed with your question.

Thank you, good afternoon. I have two questions, please. You expressed the dividend policy in a $65 environment. Does that mean there's some flexibility in terms of the dividend growth rate above or below inflation, if the oil price is either below or above $65 a barrel?

And the second question was to get a feel for the PSC sensitivity within the 120,000 barrels a day of Iraqi oil you're targeting net to yourselves for 2013.

Your question was around dividend if the oil price goes above $65?

That's right.

That's all right. Now, we gave a number which we wanted to be clear and simple of our dividend policy for the next 65 -- for the next four years. And we said that it's based only on the assumption of $65 a barrel, which means that we are capable of absorbing the other very important assumptions in our plan which are, for example, euro/dollar exchange rate or gas demand, or many other assumptions that we have in our plan.

Having said that, in the event of major changes in market conditions, suppose that we are led to change our scenario of oil prices and, therefore, we will change the way in which we see the future for oil prices, on that basis we will discuss a re-basing of the dividend.

PSA.

PSA. So is it a satisfactory answer?

Sorry, (technical difficulty) on the dividend was a satisfactory answer.

It was on the dividend?

Yes, and thank you.

Okay.

So let's move on the PSA. So the PSA, within the limited variation of price around $65 per barrel we can confirm our guidance of 1,000 barrel per $1. For larger variation, just to give you an example, at $80 a barrel -- $80 per barrel in 2013 we will see a reduction of our average growth rate of 0.5%. That would be the impact in term of price.

So can I check that the Iraqi volumes are not changing that PSC sensitivity relative to where it was previously?

No.

Okay, thank you.

Next question comes from Mr. James Hubbard from Morgan Stanley. Mr. Hubbard, please proceed with your question.

Thank you. Good afternoon, three questions please. The first one is your scenario of $65, basically you're saying you are going to get your debt down from where it is now to below 40% and obviously cover CapEx and dividends. I struggle to make that math work. Do you include any disposals in that assumption over and above the pipelines which are in the process of being disposed? That's the first question.

The second one is you've give your guidance for gas and power ex the pipelines, could you just give us a rough idea of what the EBITDA of the pipelines has been?

And finally, now that you have a major presence in South America with Venezuela doing fine and Perla, how do you regard your holding in Galp, and what do you intend to do with that?

Okay. First of all, on your first question the disposals we include in our plan are the disposals we announced. That is the Italian gas businesses, the distributor oil of the gas in Brazil.

International --

The international pipelines.

European pipelines.

The three international pipelines TAG, TENP and Transit Gas, nothing else than these disposals.

Your second question was around the gas pipeline. You wanted to know the value?

Yes, the EBITDA. Now that that's excluded from your EUR4.4b EBITDA guidance for Gas & Power --

No, we --

What would that guidance be if you still had the pipelines?

No, we expect to cash from TENP, Transit Gas and TAG, of course this is an estimate, a number around EUR1.5b and we expect to cash them within the end of this year, which is the engagement we took with the European Commission.

Now on your third question I think your question was around Galp, no?

Yes.

Now around Galp we, as you certainly know, we have a standstill agreement until December 31 of this year. So far it has been a very nice investment for us, because we invested around EUR900m and we got back around EUR1b so far of dividends and tax benefits. So let's say this has been an investment which has been already repaid.

We said several times that the situation of being a minority shareholder in a listed company is not something we like to be forever. When the standstill agreement will expire that is at the end of this year, we will evaluate all the opportunities that may arise.

Okay, very good. Could I just come back to the pipelines, you just mentioned the potential sale price there. Could you just say for those assets, those three that are being sold, what was the 2009 EBITDA that they generated?

I'm not sure I've understood, could you please repeat? Wait a second, somebody has understood.

EBITDA 2009 for the national pipelines.

Oh, EBITDA --

(inaudible - microphone inaccessible)

Ah, EUR200m, the three pipelines made EUR200m. For this reason when we set a target of EUR4.4b EBITDA for the four years plan this means that we believe to be capable of recovering those EUR200m in other parts of the business.

Okay, thank you.

Thank you very much.

Next question comes from Mr. Barry MacCarthy from RBS. Miss MacCarthy -- oh sorry, Mr. MacCarthy I beg your pardon, please proceed with your question.

Thank you, good afternoon. I wanted to ask about your position and your plans for Union Fenosa Gas and if there is an ownership issue there which remains to be resolved?

And secondly on the Livorno refinery, you said you had scrapped plans to sell that refinery. Are there any plans to close it or to convert it to a terminal perhaps? Thank you.

Well, on Union Fenosa Gas I think we will stay where we are. We think that it's somewhat a strange position to have as a shareholder our main competitor. But if this is good for the Spanish authorities it is good for us as well, so we are not debating this issue further. Union Fenosa Gas continues to perform reasonably well. We are satisfied with our presence in the Spanish market. And so we will carry on with this share without debating possible alternatives.

As for Livorno, well, Livorno, as you said, we tried to sell this refinery to reduce further our investments in this business last year. But we realized that it's practically impossible to find buyers for refineries nowadays. It was impossible last year, I think it is even more impossible this year, in which everyone is announcing divestments from the refining business. I think I read yesterday that Chevron is planning to sell all its refining capacity in Europe.

This leaves open many alternatives for the future of Livorno and also of other refineries in Italy, which we will evaluate in an appropriate time what to do to prove our industrial setup.

Okay, thank you very much.

If there is no more question, as I'm told.

The control room confirm there is -- sorry there is another question from Mr. Kenney, Jason from ING. Mr. Kenney, Jason please proceed with your question.

Hi there, it's Jason Kenney from ING. A couple of questions if I may. Firstly on the cost savings, I note the biggest piece of the cake is 48% worth of corporate and other cost savings over the 2006/2013 time period. Just wondering if you could maybe highlight what exactly is entailed in that corporate and other piece? What has been done and what is still to do in that particular part of the pie?

And then secondly, I note in your opening comments on Snam Rete Gas that you've been under some pressure from investors to sell Snam Rete Gas, and actually you've been very impressed by the total shareholder return by keeping that stake. But is it not a requirement to sell down Snam Rete Gas in time from the EU, and actually there's only an Italian Decree that's been stopping you from deconsolidating that sooner rather than later? And ultimately you do still see Snam Rete Gas outside of your business rather than inside of your business in the medium term?

Okay, listen while I ask Alessandro to get prepared to answer your first question that is our cost reduction program the 48% on corporate and what we plan to do for the future, let me elaborate on the Snam Rete Gas issue which requires a somewhat long answer if I may.

First of all, I would like to reiterate that the fact of not having sold our regulated businesses has generated a return of 65% in the last five years, which means that if I had sold this business when I joined Eni as required by many, including the Italian Regulator, I would certainly not have pursued the interest of my shareholders.

Now having said that where do we stand now? Well, the European Union last year, I think in October, issued the so-called Third Directive. This Third Directive gives to each member state a choice either to choose the ownership separation of the gas networks, and therefore obliging the operators of gas to divest from the networks. Or to choose the operational separation that is to organize the company as a separate company with all a series of governance requirements which will make the company an independent company, even if the ownership remains in the hands of the gas operator.

The member states have to choose which way to go by March 2011. As a consequence of that we have to wait and see what the Italian Parliament, because this is a question of Parliament, will decide when it will apply this EU regulation into Italian Law.

Now suppose for a moment that the Italian Parliament goes for an ownership separation. Well, at this point we will sell the transportation, the transport of gas because we are obliged to do so by the Italian law.

Suppose that the Parliament decides for an operational separation. Well, at that time we will take a decision of what is more appropriate for us, for our investors, for our shareholders. Suppose at that time we will decide for a sale this will in any case require the approval of the Italian Government, which has to make a special decree in order to sell even one share of Snam Rete Gas, since they hold the golden share in Eni. And this is a necessary requirement.

In all these contexts, as you can see, there is not much we can decide in the next say 12 months. Well, this is not time that we are going to lose, because we believe and particularly I believe strongly, that in the next 12/18 months Snam Rete Gas will perform particularly well because it will harvest all the benefits from the synergies stemming from putting together the transportation, the storage and the distribution of Italgas.

So I am expecting that even the next 12/18 months the returns that we will achieve from our shareholding in Snam Rete Gas will exceed the cost of capital already. And therefore this will create value. So it's not time lost, it's time gained.

That's very clear, thank you very much.

Thank you.

As far as the cost that we have incurred in the last five years period and to which we succeeded in realizing a significant saving, in particular as you have pointed out in corporate. The efforts that we made in the last five years related predominantly to the rationalization of the number of legal entities componing our Group. And accordingly all the administrative and financial structures which previously operated with these legal entities, we were in a possibility to reduce these -- the headcounts accordingly.

So predominately the rationalization, the saving in corporate comes from the rationalization of the legal entities and administrative cost associated. And then since we made a significant investment, a significant effort in the prior years, in particular in the IT area, then we are benefiting of the effects of having rationalized also the informational system.

Previously, we had a lot of informational system operating throughout the Group. Now after the rationalization we have only one integrated system. And of course we have to maintain, but the costs associated for the maintenance are significantly lower than before, so all in all this was the result of the process that we made in the last five years, in particular in corporate.

Just let me add to this that I believe that Eni, and particularly at corporate level, has a long way to go to become efficient. And we have still to make cuts, important cuts, and this will not be cutting muscles but cutting fat.

The point is how we can do it particularly in Italy where all these things are difficult as you probably know as in most of continental Europe. But no doubt the targets we have set of an additional cost saving of EUR1.1b I think is a number that will be increased in every subsequent strategy presentation that we will be making in the next four years.

Okay, many thanks.

Thank you.

Actually, could I just ask one other question if I may, one for Claudio, I'm interested in the Russian exposure that you have that you gained through the Yukos deal back in 2007. And I know that you've got sizeable resources in Arctic Gas and Urengoil. But there is one of your Russian assets mentioned in the presentation. When do you expect significant progress with those very large reserves in Russia?

Yes, well, then I will leave Claudio to answer more specifically on the investments that we plan to do in Arctic Gas or Urengoil and the production that we plan to make. Just let me resume to you that what we have done, when we acquired this former Yukos assets in 2007 we acquired essentially three things. We acquired the assets Arctic Gas, Urengoil in the Yamal Peninsula. Then we acquired 20% of Gazprom Neft. And then we acquired miscellaneous things like a piece of distribution, piece of refineries, a portfolio of all assets.

Well, since then we have sold Gazprom Neft. We have sold practically all the miscellaneous and we are left only with Arctic Gas and Urengoil.

Now in Arctic Gas and Urengoil the net cost of that acquisition is, if I well remember, $0.60 per barrel. So we have bought at $0.60 per barrel gas reserves in Arctic Gas and Urengoil which are made out of gas but also of condensates.

Now from that moment on we started the development, and I think we expect the first production by 2012. So maybe you can give the number of what we have there.

Yes. Our share will be about 45,000 barrels per day on the first field Samburskoye. We have already spent 100% $150m and we are going to spend 100%, our share is 30% by the end of the period, by the end of this project, $500m. That are the figures.

Development costs.

Development costs yes.

So in fact the total development cost will be for a production of 40,000 barrels.

Equity yes.

Equity for us, one-third of $500m.

Yes.

So $150m, then from that moment on the following key question is how much of this gas will be sold in Russia and how much of this gas will be sold outside of Russia? Because as you probably know there is the difference between Russian -- gas sold in Russia and gas sold outside of Russia is like from one to three. So this is another key issue that we would be facing in the near future.

I'm right in thinking that Samburskoye is just the tip of the iceberg though and you've got significant more development further out, yes?

Not sure I've understood.

[Nothing's possible].

The Samburskoye 45,000 barrels a day that's just a tip of the iceberg as far as the whole asset base is concerned.

The tip of the iceberg, the production. Oh yes, well, it will increase when we will be developing the whole field.

Just to give you an idea the two -- 100% production of the first field is 150,000 barrels per day. The second field is 105,000 barrels per day. And the last two fields that we are going to develop in 2016 and '17 will produce each 100,000 barrels per day. So we have more or less a production 0.5m at the end of the development.

100%.

100%.

We will have 30% of it.

Many thanks.

Thank you.

There are no more questions at the moment.

No more questions, so the strategy presentation is ended, and I will thank you everybody for coming here.

Ladies and gentlemen, the conference is over. Thank you for calling in.