Paolo Scaroni – CEO
Claudio Descalzi – COO, Exploration & Production
Umberto Vergine – COO, Gas & Power Division
Alessandro Bernini – CFO
Daniela Ferrari (ph)
Alejandro Demichelis – Merrill Lynch
Alastair Syme – Citigroup
John Rigby – UBS
Theepan Jothilingam – Nomura
Mark Bloomfield – Deutsche Bank
Jason Kenney – Santander
Neill Morton – Berenberg
Colin Smith – BTB Capital
Eni S.p.A (E) 2012-2015 Strategy Presentation March 15, 2012 11:30 AM ET
Good afternoon, ladies and gentlemen, and welcome to ENI Strategies Presentation. For the duration of this call, you will be in listen-only mode. However, at the end of the call, you have the opportunity to ask questions.
I’m now handing you over to your host to begin today’s conference call. Thank you.
Good afternoon, ladies and gentlemen and welcome to our Strategy Presentation. This afternoon I will give you an update on our prospect and targets in each of our main divisions. But before we do that, I would like to highlight how ENI has consolidated its position over the past years and why we’re now about to enter the period of rapid growth which would last not just for the next four years but for the next decade.
In E&P, the restart of our activities in Libya is leading towards fast recovery in our 2012 production. In 2011, we’ve also made significant progress on key projects including the FIDs of giant fields in Venezuela and Russia adding certainty and visibility to our near term growth prospects.
Of the key reason why ENI is stronger now than a year ago is the success of our restorations in Norway, West Africa and Mozambique, which will drive our strong growth to 2021 and beyond.
Turning now to our medium downstream businesses, over the last year, we have taken further steps to increase our competitiveness in what remains a challenging market contest. In gas and power, we’ve concluded contra-renegotiations with two of our main suppliers, Sonatrach and Gazprom. We re-leverage on our improved cost and flexibility to continue to build out European market to print. A strategy which will position us well to recover profitability as the market tightens.
In R&M and chemicals will further stream-lined our operations and have targeted additional cost savings and optimizations in each business. In chemicals in particular, we’re also targeting a number of initiatives, which will significantly improve our competitiveness.
Let me now take you through our strategy and targets in more detail. In E&P, our consistent track record of exploration success over the past year is the key driver of our growth. While 2011 has been an extraordinary year in terms of the size and potential on our new discoveries, it is not an outlier in terms of results. Over the past four years, we have discovered around 4 billion BOE of new resources almost double our cumulative production of 2.5 billion BOE with the progressive strengthening of our resource base to 32 billion BOE.
Meanwhile with unit exploration cost of around $1.7 per barrel over the past four years, our exploration success supports our capacity to deliver sustainable returns on new projects and our almost ENI oil price scenario, and then IRR in excess of 20% at our planned scenario of $90 for 2012 and 2013 and 85 thereafter.
Our consistence performance confirms the effectiveness of our exploration strategy with this focus on proven basis and a select number of high potential frontier teams. Building on the success over the next four years, we will increase our exploration efforts to further strengthen the basis of our long-term growth.
Let’s now take a closer look at our upstream growth profile. Between now and 2015, we will add around 700,000 BOE per day of new production through, over 60 major start-ups including three of our fields in the Yamal peninsula in Siberia, Goliath in Norway, Perla and Junin 5 in Venezuela, block 1506 in Angola and of course Kashagan, which we’re on track to start-up by the end of 2012.
Of the total new production which will come on stream by 2015, around 70% comes from exploration. What the remaining 30% comes from the acquisition of underdeveloped resources, in particular, our fields in the Yamal peninsula and Junin 5.
This solid pipeline of projects will lead to average production growth of at least 3% a year to 2015. At our planned scenario of $90 per barrel for 2012 and 2015 and $85 per barrel thereafter and normalizing 2011 production for the Libya impact. Increased scale and the focus on oil compared to gas over the plant period, we drive an increase in cash flow per barrel of about 10% to 2015.
Looking beyond 2015, following the discovery in Mozambique, we have raised our long-term growth target from 2% to 3% a year. Africa, we continue to be the backbone of our production and growth in the next 10 years driven by growth in Angola, the start-up of Mozambique expected by 2018 and further exploration potential in existing and new countries including Ghana and Togo.
Meanwhile, in North Africa, production will continue to be resilient with very low natural decline. Our other key growth hubs will be Russia, where between 2015 and 2021, we will start-up two more Yamal Giants in the same peninsula where we will start the first (inaudible) in 2012.
Kashagan, with the ramp up of – excuse me, Kazakhstan with ramp-up of Kashagan and further potential from our development of Karachaganak. And thirdly, Venezuela, where he full field development of Perla and Junin 5 will contribute around 880,000 barrels per day of production by 2021.
In Europe and North America, we will see a broadly unchanged production level with high natural decline compensated by new projects, and in particular the screw guard and have these start-ups in the Barron Sea, which will contribute around 70,000 barrels per day by 2021.
All of this heads-up to the strongest project pipeline in our history. Claudio will give you some additional detail later on this afternoon, but given the breath of the portfolio, we will also organize a specific upstream seminar in the early autumn.
Let’s now turn to Gas & Power. The timing and terms of the disposal of our State in R&M will be addressed later in this presentation and I’m sure in the Q&A. However, I would like to take this opportunity to highlight how the perimeter of our Gas & Power division is going to change following the consolidation of R&M and of our interests in international pipelines, target temp and transit gas.
The resulting business will be made up of two main parts. The first is a semi-regulated business which is composed of our other international pipelines and some local distribution. This part of Gas & Power which in 2011 accounted for around €600 million of pro forma EBITDA we provide steady profitability over the coming years.
The second is our gas and power marketing business which has a stronger diversified portfolio of long-term gas supply contracts, power generation capacity of around 5,500 Giga-watt and a leading position in the European gas market. This is the portion of our Gas & Power which has been affected by the negative market environment including the continued availability of lower priced L&G spot cargos and the significant falling demand in particular, in the second half of 2011.
In this difficult and volatile market, the key issue is supplied. Long-term contract are essential to guarantee stable supplies to our customers. But they also need to be different from what they used to be. Their price needs to be competitive with spot gas, volumes need to offer the flexibility to cope with demand volatility and terms need to adapt when market conditions change. These are the pillars along which we have renegotiated with Libyan NOC in 2010 with Sonatrach in 2011 and with Gazprom in 2012.
We will continue to work on improving the competitiveness of our supply portfolio opening talks with stock oil in the second part of this year. Meanwhile, our improved cost position will sustain growth and consolidate our position in European retail on the back of over 1 million net new clients added in 2011.
Over the past year, we have also worked to enhance our trading capabilities, trading is here in London, the office is next to this one. The people here are in close contact with all our divisions to capture the benefits of market volatility and price differentials in different markets. One respect that the current market weakness will continue to put pressure on our merchant business in the first part of the plant period, we are confident that from 2014, 2015 onwards the European gas market will tighten again.
On the demand front, we see a recovery and then long-term growth in volumes driven by economic development and fuel switching to gas in line with the European objective of reducing CO2 emissions. In total, we expect EU demand to increase from around 500 BCN to over 560 BCN by 2015 and close to 600 BCN if we look forward to 2020.
At the same time, we see European supply tightening domestic gas production will decline from the current 173 BCN by around 3% a year to 156 by 2015 and 130 by 2020. L&G imports will level off after the peak in 2011, with capacity growth being absorbed by strong demand in the far, East and Latin America.
And traditionally European suppliers in particularly Northern Africa, we struggle to increase exports because of strong domestic demand. In this context, our diversified long-term supply portfolio, our increased equity gas and our market leadership in key European countries would be significant competitive advantages, leading to grow with profitability in Gas & Power.
Turning now to R&M our refining business continues to face a difficult environment with stable of declining demand for products and persistent over capacity, especially in our core Mediterranean market. We expect the scenario in Europe to show limited improvements from now to 2015. Simple refineries will likely come under pressure from tightening product quality regulations, driving a 15% reduction in refining capacity and then modest improvement in refining margins. In this context, our strategy to return to profitability is fully based on self-help measures.
We are working to support margins through the full exploitation of conversion capacity with the start-up of our EST plant in San Lazzaro and extensive integration of our refining system, greater supply flexibility to take advantage of opportunities in the pricing of different crude and enhanced integrated trading operations. We’ll continue to focus on cost reductions and in particular on energy savings, and labor and maintenance costs.
Meanwhile, we will consolidate the profitability of our marketing business leveraging on the re-branding of our network, the full automation of stations and the opportunity to expand non-oil activities offered by the liberalization process in Italy.
Overall, this actual will improve refining and marketing results by around €550 million by 2015. The same scenario we experienced in 2011 with over €400 million coming from the refining segment.
Now, why we do not usually spend much time on any chemical business, this year, we would like to give you a little more detail because we are launch a turnaround strategy. This business accounting for around 2 billion or 2.5% of our capital employed has always been weak with a fragmented industrial footprint. On top of this, in recent years, the European chemical sector has suffered from increasing price pressure on base chemicals with ethylene production cost, a multiple of those in the Middle East.
As a result, despite cumulated efficiency gains of €360 million between 2006 and 2011, in positive market conditions when everything goes well, our chemical business makes limited profits. While in negative market cycles, it absorbs cash. To tackle this issue, we have divided a strategy based on three main pillars. The first is the focusing of the business increasing our prices in added value products such as (inaudible) where we have a leading market position in Europe.
Demand for these products is expected to grow in coming years, and margins are resilient even at higher feed stock prices. In this segment, we target an increase in sales of 50% to 2015. By which time added value products we make up over 40% of our revenues.
The second pillar of our strategy is international expansion, building appraisals in emerging markets especially in Asia and Latin America through licensing agreements production alliances and joint ventures. We target the doubling of extra European sales to around €700 million by 2015. And the third is further efficiency and capacity rationalization, as well as energy saving and further integration of our production cycles, we are planning to close on convert loss making sites, cutting our projected land capacity by 20% and supporting our focusing on EBIT value products.
We have already begun to implement this approach with a project to build an innovative bio based chemical complex on the site of structure and loss making basic chemical plant in subgenera (ph).
All of these actions we deliver over 400 million of additional EBIT by 2015, this scenario, the web scenario we experience in 2011. And this efficient and re-focused business, with its exposure to more profitable and defendable markets we’ll be able to better offset negative cycles and capture the benefits of the positive strengths.
To reflect the strategy, the new strategy, we have remained in the business any Versailles. It would be expert led by the Daniela Ferrari (ph) who is here at the end of the table, who joins us with 25 years of experience at ICI enhancement, and who would be happy to answer your questions during the Q&A session.
Turning now to our listed non-core assets, over the past year, we have progressed in our strategy of unlocking value. Now, with regards to our 53% stake in SNAM currently worth almost €7 billion at market value, our exit would be regulated through a government decree to be issued by the end of May, the end of this May and would be completed at the latest by September 2013.
In terms of how this separation will occur, we do not yet have clarity on the contents of the decree. And we’ll of course update the market when we do. However, the position of our board of ENI’s board is that the disposal process, we need to meet three criteria. First, it will need to be friendly to ENI’s shareholders by which I mean a deal which recognize the full value of our stake at SNAM.
Secondly it will need to protect the interest of SNAM shareholders by limiting the possible overhang an SNAM shares. And thirdly it will need to strengthen ENI’s balance sheet in view of our extraordinary growth prospects, building on exceptional exploration success.
With regards to our stake in Goliath this is not the first time we talk about Goliath we reiterate that being a controlling shareholder in a listed company where much of the value is in the minority holding is not part of our strategic priorities. That said, we are in no rush to say this is an asset with great potential, particularly with regards to its position in Brazil and now in Mozambique together with us. And we are pleased that the market is starting to value its growth prospects. In this context, we are talking to our partners to find an agreed disposal option within our shareholder agreement which aspires in March 2014.
This concludes my overview of ENI’s Strategy and targets. And I will now hand you over to Claudio for a closer look at E&P.
Thank you Paolo, good afternoon ladies and gentlemen. Let me start by reinforcing our priorities and our strategy drivers. Our focus is on exploration and the tiny conversion of resources into their sales and production. And at the same time, on fighting depreciation and enhancing the recovery factor in the existing field to continuous recess wire management.
The key to meeting these goals and mitigating recess is development and consolidation of critical skills and technologies which we leverage through increasing operators. We remain highly focused on strong agency performance, this year we registered and filed an improvement in our safety indexes. Our LTI index was down by 40% compared to the average of the previous four years. On really, despite the significant increase in the number of pirated wells which had nearly double since 2005, we recorded zero grow outs in the last eight years.
Continuous improvement on safety is our first priority. We put strong commitment on initiative promote individual awareness on safety including training and a strict follow-up on execution. We are delivering more than 200,000 hours per year of training, dreams (ph) and simulations and assessment on our people agency capabilities.
And now I will give you some detail on our growth strategy. I will focus first on exploration where our recent successes and high potential exploration assets are the foundation of organic growth for the next decade and beyond. And then I will update you on our main development projects.
Last year was very positive for our exploration we drilled 56 wells of which about 80% were successful. And we have added 1.1 billion barrels of new resources. We also continue to rejuvenate our portfolio by adding new acreage notably in Indonesia, Australia and Angola.
Looking forward the next four years, our strategic guidelines remain unchanged. We will continue to focus on assets, with high methodology and faster into market, concentrating on place where we have experience and good knowledge over the geological model. These include West Africa things, such as margin in Ghana and Pogo and the Pre-salt in Angola, Congo and the AFC, the East African territory place, the Barron Sea.
We are also renewing our portfolio in New Basin, close to areas with high demand growth. Our exploration portfolio we continue to deliver industry leading results. Over the next four years, we aim to discover about $1 billion equivalent of resources at an average unit exploration cost of $2 per barrel.
Let’s take a closer look at three of our most promising exploration target. The first is the Barron Sea, where any statutory is the – the operator presenting all three large oil discoveries in Goliath, Skrugard and Havis. The second Skrugard Appraisal well found about 80 meters over the carbon calling confirming a world class discovery. And we have it in Skrugard complex accounts today for more than 500 million barrels of recoverable resources.
Following this major successes, we believe we have cracked the geological code in this part of the basin and are confident in the significant resource upside. We unlocked this true and aggressive exploration program with at least a further wells in the next forty years and 220 million your investment. And we will maintain our leadership in these exciting explorations from figure leveraging on our stronger asset base.
Let’s now turn to Mozambique Mamba (inaudible) basin is the transformational discovery. We estimate the research is found with the first two wells at about 30 Bcf organic place, or 5.4 billion barrels of oil prevalent. The test on Mamba North one, the first performed in the area confirmed excellent reservoir and well production characteristics in final completion configuration, production per well is expected to reach over 140 million cubic feet a day approximately 25,000 barrels per day.
The gas is high quality lean and without sour components. The resources we identify is sufficient for first stage of development. The first step will be the utilization with area one structure and then the finishing of the common plan of development. Placid exploration offside, we plan to drill six to eight further wells and acquire further seismic data in the area of Mamba, investing €400 million in the next couple of years. The objectives which will validate additional four or five structures, most of which are entirely in the area four.
And now some details on the Pacific Basin. In Australia, and Indonesia building on 700 million barrel already is covered, we are expanding our portfolio and fast tracking the evaluation of recently acquired exploration assets including the North Canal in Indonesia and Avon Shale, Harold and Blackwood in Australia offshore. All of our program in the area are with the next full year encompasses 24 wells and €300 million of CapEx with the objective of fast track in development with synergies through existing L&G facilities.
A good example of these approaches expanded the John Creek area which has reached 4 bcf of gas in place through the John Creek and John Creek in North East discoveries. The development plan was approved by local authorities at the end of last year, we foresee the FAD by 2013 and we target the start-up by 26 days.
As a result of the sizable blocks already secured, over the next four years, we will increase our level of activity to 300 wells from the 240 scheduled in the previous plan. We will increase our exploration investments to €5.5 billion. About 20% of this CapEx will be dedicated to appraisal campaign to expedite the time to market of the significant discoveries.
In geographical terms, 60% of the CapEx will be concentrated in Africa, which we’ll continue to provide a backbone of our production in future. We’re also increasing our exposure to Far East which will account for about 10%. Europe will absorb 15% mainly focused on Norway.
Compared to our previous plans, we have increased the share of exploration CapEx devoted to frontier areas from 30% to 40%. Our successful track record on exploration will further consolidate our research base in the long-term. However, discovering resources is not the only challenge of the industry, the second and possibly the most complex challenge nowadays is converting resources into reserves and then production and achieving these in a timely manner with an efficient use of capital and lead a strong technical focus to guarantee efficient and reliable production over time.
Our objective is to achieve these goals just through relentless attention in day by day activity but also through specific initiatives. We have fine-tuned our processes and organization to constantly monitor the status and value of resources in the different phases of conversion. For instance, we create a dedicated function and allocated bandwidth to accelerate the appraisal of this core services.
We monitor the status of silent recourses and the bottle neck their development. And we have identified specific KPIs to monitor resources conversion. Through these actions, we will be able to develop more than 90% of the exploration successes of the last three years within eight years of their discovery.
Our focus on exploration and time to market translate into robust pipeline of project and startups, within the plan and beyond, which underpins our goals of long-term production growth over 2 million barrel per day by 2015 and around 2.4 million barrel per day by 2021 at $85 per barrel.
Looking at our full year plan in more details, startups we contribute around 700,000 barrel per day of new production by 2015. Of these 80% we come from giant fields with long less in plateau, approximately 75% is already sanctioned. And most of it will be operated directly by us. The pipeline of project is geographically diversified with 20% of the new production coming from development in OCD countries and 30% from Russia, and the Caspian area.
However, while our production is geographically diversified, it is also focused on a number of key hubs with synergies in term on geological and local expertise, infrastructure and relationship with local communities. And we give a material contribution to long term production.
I will now give you an update on the main developments. The first is the Yamal hub in Russia, where we have (inaudible) to develop. Here, we’ve finalized our gas sales agreement and took the final invest in the field on the Samburskoye field. First phase development progress in February was 91.5% with drilling campaign ongoing. First gas is confirmed like the middle of this year.
In Q4, last year, we also took FID for the Urengoskoye field, drilling activities have started. Startup is expected in 2014. Activities are progressing also on the (inaudible) field or production startup is forecasted by end of the year, while gas productions will startup in 2014.
Lastly, the severe of fuel would be in production by the end of 2015 and activities are progressing for the definition of the field development plan. Overall, our Yamal Hub provide over 120,000 barrel per day of production by 2015 and we confirm our expectation of long term total reduction of around 20,000 barrels per day, 200,000 barrel per day sorry.
In the Barrier Sea, beside exploration activity, the Goliath project is moving forward. Overall progress at the end of January was 38% and production was startup confirmed by Q4 2013. Last year we installed the hate subsequent plates, this year we will start drilling campaign with this (inaudible).
Norway will contribute around 160,000 barrels per day to production by 2015 and around 200,000 barrel per day in the long term, our Kazakhstan hub as two main projects, Kashagan and Karachaganak. On Kashagan, we are getting close to the commercial production of the first phase we are currently undergoing mechanical completion and cohesion. The overall physical progress to reach commercial production was 99% at the end of February. The first 16 wells enquire for the initial stage of production at already drilled and ready to produce. Four further wells will be made available for production during summer.
Startup is expected by the end of the year with the rate of 75,000 barrels per day and the gradual ramp up to a capacity of 370,000 barrels per day by early 2014. Overall, Kazakhstan we provide 170,000 barrels per day of production by 2015, and around 200,000 barrels per day by 2021.
In Venezuela, our Perla and Junin 5 projects are progressing well. With regards to Perla in, December we finalized the commercial agreements in two to four phase, one which will reach production of 300 million standard cubic feet a day of gas by 2014. Startup is expected by next year. Our priority for the Perla gas is a domestic market, however we are also evaluating explore opportunity in coordination with Perla basin.
For Junin 5, startup is expected by 2014, and we are working with Perla basin to bring forward early production to the end of this year using existing Perla basin facilities. Overall, our Venezuela have, will provide 65,000 barrel per day of production by 2015. And we’ll have a long-term production of 180,000 barrels per day.
Finally, (inaudible) and Africa is an extremely important hub. Apart from Mozambique which we already discussed, the key projects for made the long-term growth drive, block 1506 in Angola where we have started this crucial phase for the west hub and drilled the first four wells of Pier 245 in Nigeria for which we leave an FID by 2014, Gas and condensate project are relating to (inaudible) discovery in Ghana for which we are renovating both domestic and export options. Overall we expect the sub-standard to provide 500,000 barrels per day of production by 2015, and something in the region of 750,000 barrels per day in the longer term with a sizable contribution from Mozambique.
These enhanced exploration and the development plans would be fueled by investment of almost €45 billion over the next four years, an increase of 14% on the last plan. The increase is largely driven by Mozambique which between exploration and development accounts for over €3 billion of CapEx and projects in the balance sheet. It also reflects our increasing exploration activity in Ghana and Indonesia and the new developments of OPL 245 in Nigeria and Azania in the Gulf of Mexico.
This CapEx will generate stronger term going forward. The breakeven prize for our overall portfolio of ongoing projects is $45 per barrel while generate returns from our startups over the next four years is more than 20% of our planned scenario.
As a final and essential remark, let me summarize the expected results of our problem activities internal production and value. First, we will believe a sustainable production growth at the high-end of the industry. Our growth to 2015 will be at least 3% year on average. These targets include contingency and asset rationalization over 200,000 barrels performance day higher than ever before.
Our growth would be resilient in the contest of higher than focused oil prices. At $100 per barrel we will deliver growth in the region of 3% a year on average to 2015, compared to our previous planned growth rate of 2% to 2014 at the same scenario.
Secondly, as well as growth, we will generate value our cash flow per barrel is already one of the highest in the industry underpinned by an efficient cost position. Last year we had one of the best exploration cost in the industry, $1.2 per barrel and down from the last three years average of $1.9 per barrel. The same applies to OpEx where between 2009 and 2011 we registered an immediate release in average of $6.3 per barrel.
Starting from this excellent base, the scale introduced to our project will enable us to grow cash-flow per barrel even farther at a flat $85 a barrel scenario. To sum up, our exploration results on the period project portfolio which is the strongest in the last decade, we will deliver the value of this portfolio leveraging on operate ship, development and deployment on new technologies and continued focus on time to market. Thank you for your attention.
I will now hand over to Umberto.
As Paolo mentioned, the European gas market we remain complex in the short term but we expect to gradually see through the balancing of improving in the medium and long-term. Let’s look at the short-term first.
In thermo supply over the next 12 to 24 months, we expect a slight increase compared to last year. While we do not see growth in the L&G from Qatar since regulates this planned production target gas supply will increase due to the resumption of green stream. Furthermore, additional volume might be important via the new non-stream passage.
This increase in imports will be partially compensated by the decrease in European domestic production which will reduce supply by around 10 this year over the next two years.
Meanwhile demand growth is expected to be sluggish into the weak economic situation which will particularly impact on industrial gas demand increasing competition from the renewal and power generation tool.
The combination of slightly higher supply and sluggish demand will result in continuing oversupply to the European market, despite the benefit from renegotiation in the short-term we therefore expect spot gas to remain at discount to long term oil and supply resulting in continuing competitive pressure on the market.
Looking beyond the next 12 to 24 months however, we expect European market to rebalance and then show further improvements. This will be driven by three key trials. The first one is demand growth, especially in the Pacific area where between now and 2015, consumption will increase by 16% or around 90 bcf. This will largely absorb the new energy production coming upstream in the region and those will attract some of the catalyst reply which is currently being delivered to Europe. Furthermore to South America and Middle East will see an increase in demand for stop cargos which also absorb some of the supply from Europe.
The second one is that North America will continue to be an island in gas serves. United States domestic production will grow but we expect explores to be limited and subject to regulatory constraints as the US government may not want to encourage an increase in domestic gas prices.
The third trend is, rising input requirements in Europe, which will increase by almost 80 bcf to 2015 through the combination of growing demand and declining domestic production. Given the marginal expected contribution of European shale gas by the time and the tightening of the energy market, we expect additional input requirements to be mainly satisfied by pipeline gas under the long-term contracts.
Over the next four years, we also expect internal European gas market to become more integrated, thanks to the construction of new interconnection. Easier gas circulation, we create additional commercial and trading opportunities for company like E&I with diversified supply contracts and strong market position.
Moving on to our strategy, supply is the key factor to cope with short-term market volatility and to increase profitability when the European market tightens. It has to be competitive with spot price then to be flexible on takeaway volumes and third to give both suppliers and buyers the option to renegotiate more frequently if required by market conditions.
We have already made good progress on this front in the last two years we are close contract renegotiations with Libyan supply, with Sonatrach and in the recent weeks with Gazprom which between them account for almost 70% of our supply portfolio.
So, looking forward, we will continue to work on the competitiveness and market reflectivity of our portfolio, opening negotiations with stock oil, in the second part of this year. As a result of these actions, we are now in a better position to pursue our strategy. Despite the current market turbulence we will continue consolidated our market position and gradually we recover profitability as the market tightens.
Let me now take you through the key conventional strategy which will drive sales growth over the coming years. We have two distinct commercial objectives. The first is to consolidate our leading European position in the business gas market where we have the well balanced portfolio in terms of geographies, cost in the segment and contract duration.
Over the planned period, we will increase our sales to industrial power join and resellers by 13 bcf. We will do these through our strong conventional platform in the largest consuming countries like Italy, France, Germany, UK, Spain and Belgium and in our newly target markets, the Netherlands, Austria and Hungary.
In particular, our growth will be driven by our reliable and increasingly competitive supply portfolio and our capacity to offer clients tailor-made solutions with a multi-country approach. In doing so, we will leverage our decade of experience in the gas market to provide wide range of services including risk management and prospect to storage contract. Our second commercial objective is to increase our penetration in European with this segment, increasing our customer base by almost 30% in the next four years.
We are already strengthening our position in this segment. In fact last year in Italy, we already did 500,000 new contracts through our dual offer, dual fuel offer and innovative sales channels.
In Europe with acquisition of outer gas and the new one, we can now count on a resilient customer base in France and Belgium, highly complementary to our operation in the business segment in those countries.
Looking forward, while we continue to grow in the European segment using our valuable experience, green in the Italian retail market, our high quality service and customer care and our multi-channel sales platform spanning from any branded energy stores, local agency, online marketing and web. The combination of our market view and our actions underpins our target of growing profitability to more satisfactory levels over the next four years.
Focusing on marketing and international transport which in 2011 reported 1 billion pro forma just of EBITDA we will see an increase in 2012 driven by the recovery in Libyan supply and the benefits from the closing of the renegotiations with Gazprom, of which a part relates to 2011.
However, our underlying marketing business will continue to face market production. But looking further ahead of the progressive tightening of the European market we result in further growth in our sales and margins. We will also leverage on the flexibility of our portfolio to capture trading opportunities in Europe and the Far East.
Thank you for your attention. I will now hand you over to Alessandro for the financial outlook.
Thank you Umberto. Before we move on to our CapEx and efficiency plans I will take you through the financials impacts after the consolidation of SNAM which will occur before September ‘13.
While SNAM’s leverage is relatively low compared to its regulated peers it is relatively high compared to the core ENI oil and gas activities, that means that the consolidation process which would see in our companies net to gradually reach a financial independence would by itself lower it’s gear. Indeed stripping out the €11.2 billion of debts at dutiful to SNAM, ENI’s ‘11 debt to equity ratio declined from 46% to 30%.
If as well as the consolidation of the debt, one assumes a cash inflow brought in-line with the counter market revenue of our 53% stake in SNAM, ENI’s leverage drops to below 20%. The consolidation of SNAM would also boost ENI’s returns on capital invested from the reported yearend level of 9.8% to 10.4% on a see through basis and through ‘11 4% factoring the cash inflow equal to SNAM some market value.
Let’s move over to our CapEx plan. Our growth over the next four years would be fuelled by €59.6 billion of investments of which €6.2 billion pertains to SNAM and will therefore be then consolidated within the planned period. On the consolidated basis, this represent an increase of €6.4 billion compared to last year’s plan. This increase is driven by our enhanced exploration and development plan in E&P and in particular the new attractive opportunities we identified last year including the first trench of the Mamba project and giant developments in Nigeria, Indonesia and the Barron Sea.
Two thirds of the planned CapEx for the next four years is already committed, increasing visibility on costs and delivery of our project pipeline.
With regard to our other businesses, we have adopted a more selective investment approach with CapEx largely concentrated on the efficiency programs and re-focusing on our portfolios of the most attractive segments. It does empower assuming the same perimeter we have today, so including SNAM, planned investment will mainly relate to regulated businesses, which as you know have guaranteed returns. Marketing will account for about €1 billion of CapEx mostly in power generation to increase flexibility and maximize matches.
In R&M, we plan to invest about €2.8 billion in line with previous plan but with decreasing expenditures of refining. By the end of this year, we will complete the main development project underway in R&M, the EST plan in San Lazzaro, short and improving the complexity of our system. Remaining CapEx will include the rationalization of logistic infrastructures, the re-branding of our service stations and non-oil development.
Finally, investment in chemicals would be mainly dedicated to new initiatives expected to boost organic growth in the most profitable segments. These projects represent two third of total expenditures with an attractive internal rate of return of over 20% on top of the consolidated €1.6 billion attributable to chemical in CapEx. We will also invest around €200 million in our new bio-based chemical plant project in sub area.
Efficiency will continue to be an important part of our strategy. Since the beginning of the program in 2006, we have delivered over €3.1 billion in cost savings by streamlining our processes and driving continued improvement in our operations. Savings achieved in ‘11 amounted to over €600 million, hall for which came from enhanced efficiency at the corporate level.
Our new plan has once again increased our target for cost savings, now expected to be €5 billion in total for the ‘04, ‘15 period. This would be achieved through procurement and the logistic optimization, energy saving and increased labor efficiencies.
New projects and our strong focus on efficiency will support our cash flow generation over the next four years. At our planned scenario of $90 per barrel oil in 2012, 2013 and $85 per barrel in the following two years, our strong cash flow from operations will more than fund our increased in investments and reduce net debt to well below 40% of equity by ‘15. And this target is of course at a constant perimeter which means excluding the reduction of leverage we would occur as a result of potential disposals and the consolidation of SNAM.
Meanwhile exiting SNAM will not have a significant impact on ENI’s organic free cash flow as SNAM has historically re-invested the entirety for free cash flow from operations to fund the CapEx and is expected to continue to do so. As a result, our dividend location will change owing to the consolidation of SNAM. Under our planned scenario we confirm that sustainability of our dividend policy of growth in line with the inflation which aims to preserve the real value of the remuneration to shareholders.
So, thank you for your attention. And now, I will hand you over to Paolo for his closing remarks.
Thank you Alessandro. In conclusion, through a combination of exploration success in E&P, in operational progress in each division, we are now in a better position than ever before to deliver long-term growth and value. E&P will continue to be the main driver of our business, building organic growth from exploration success.
We are entering a period of accelerating growth. And our track record of consistently delivering around 1 billion BOE of new resources every year underpins production potential over 2.5 million BOE per day supporting our growth target to 2021 and beyond.
In Gas & Power, we have challenging short term market conditions to contend with. But our progress on the cost of flexibility of our supply improves our ability to grow in key markets and segments, and we will reap the benefit of these actions as the European market tightens in the medium term.
In R&M, our focus on efficiency in refining and consolidation of our position in marketing will return our operations to profitability. In our chemical business, we push a turnaround strategy with a focus on added value products in high growth markets.
On top of our robust business objectives, we have the potential to unlock value through the disposal of our non-core listed assets. While disposal options and timing are not yet finalized, monetizing our states in Gulf of SNAM and also significantly strengthen our balance sheet. We consider that a strong financial structure is appropriate to a business portfolio more focused on E&P. It will give us additional flexibility on our major development projects.
And with a high potential exploration campaign ahead, we would be able to take full advantage of new organic growth opportunities with attractive returns. What will not change in our proved is our prudent approach to M&A. We continue to be focused on bringing our resources to reserves and production, taken together all these actions and the opportunities give ENI a clear roadmap to growth and value creations in the year ahead.
Thank you for your attention. We will now be pleased to answer your questions. Pamela.
Hi everybody. We’re going to take some questions from the floor and then some questions from the call. So, if you wouldn’t mind putting your hand up if you want to ask a question, and then stating your name and sir name.
Hi, I’m (inaudible) Investment Bank and I had a question for Mr. Scaroni on the Gulf stake. Given what we’ve seen in the press over the last couple of weeks that American Marine has been negotiating with ENI for an acquisition path of the stake. So, my question is would – if there is an agreement found, what would you be willing to do with the other half of the stake. Would you be willing to place this in the market or would you – what would be your decision on that?
Okay, we answer every question. Yes, well, let me, since I am expecting further questions on Gulf, let me give you the full picture for a second. Our stake is more something between €3.5 billion and €4 billion. Until 2014, there is no possibility for us of selling those shares probably not even one of the shares, not even one, without the green (inaudible) here and the government, the government being the (inaudible).
So, I mean, these kinds of questions you should ask them rather than us in the sense that if they would agree for us to send 15% here, 15% there, 10%, we probably would do it. The point is that we have to reach an agreement, the three partners in order to divest before 2014. If you want my view, I believe that probably 2014 is very far to reach a solution and I’m fairly confident that we will find a solution for this divestment before that time and also I believe that this is probably more likely than not. But still we don’t have an agreement which will allow us to divest from our state.
On the other hand, as I reiterate, I’m not particularly in a hurry, this at the end of the day is our business, you know, most of the value of Goliath is I mean, inside our E&P business in particularly Brazil and now Mozambique. Now Mozambique as you have heard today, we considered most of the – there is a lot of value and Goliath is 10% of it, the market is partially recognizing this value of share prices will reasonably well, we believe that there is much more potential than that. So, we are not really pressed to find a solution tomorrow rather than six months from now. Okay.
Alejandro Demichelis – Merrill Lynch
Alejandro Demichelis from Merrill Lynch. Two questions from me, the first one is on the 2015 strategic plan. You will probably divest both SNAM and Gulf. So what would be the plan to do with those proceeds, that’s question number one. Question number two is, you’ve given us the 2021 growth target on the E&P business for 3%. What is the level of CapEx that we should be assuming that would be enough to sustain that growth?
Look, on the first question, our first idea about what to do with the procedures to payback debt, we love the paying back debt. We think that company like ours which is involved in huge projects which is investing a lot in exploration, therefore more projects ahead as to have a very strong balance sheet. Now this is the general view. So, the more we make exploration, the more we make discoveries, the more we make development, the more we need a strong balance sheet. So, that’s the general view.
Now of course we are reconfirming our dividend policy even without SNAM, I think this was the message that we received. And of course even without Gulf, so, these two things do not influence our dividend policy. And therefore as far as we can see that is 2015, we see a world in which any would need to strong balance sheet in order to develop its very exciting projects all over the world.
Now in terms of CapEx, we don’t, do not have the I cannot give you a precise figure because we have not developed 2021, the CapEx, we believe generally speaking that would be in the region where we are today, we don’t have every year CapEx over the different view.
We can say that we will be evitable at more than what we are standing now so, it’s in the range of €12 billion average that is more realized so not being improved. Also we further have some projects that are slowing down, so another project we’re entering the – the bad debt is not realized but, yes.
Yes, we’ll see – we will not have SNAM, and we will have probably some more E&P, in total we would be in the region where we are today.
It’s David (inaudible). As you know, we are long-term shareholders in ENI and this is a question for Mr. Scaroni. Over the last few days there’ve been suggestions in the Italian Press that ENI shareholders should prefer the ENI sell at shareholdings in SNAM for cash rather than just going to get off, since the spin-off could in some way be less attractive for E&I shareholders. And you yourself this afternoon have talked today about monetizing your investment in SNAM.
As shareholders, you know, I would like to state for the record that (inaudible) would be indifferent each solution results in SNAM’s 11 billion or so euros of debt being deconsolidated subject only to timing. ENI and in Italy are currently both in a sweet spot and the market is giving you credit for reducing the old debt. Execution in both cases is now critical and as the market gets the sense that you’re dragging your feet the full from growth could be quite rapid, and quite painful.
Can you therefore provide us with the comfort of saying that if the sale of SNAM does not take place by say, late autumn that will in any case proceed with the spin-off?
You’re asking the question to the wrong person. Because spin-off, this is not my decision, this is the decision of the government so really you’re addressing the question to the wrong person. But let me just add a small detail to what you had been saying. If instead of selling our stake, we would deconsolidate our stake in SNAM, for example, making a dividend in shares to our shareholders of SNAM shares, this will probably pose a downgrading of our company, because it is true that we have 12 billion of debt which we deconsolidate.
But it is also true that rating agencies know very well that in front of this 12 billion of debt of SNAM there are revenues regulated certain which offset this debt, now just to tell you that the two things are not exactly identical for ENI and for the shareholders of ENI. Having said that, I’m taking note of your declaration, as far as the question, address them to the government.
Enrique (ph) from Jefferies. Accounts to question on Mozambique, you said that the fourth quarter results call, so you might sell down your 70% stake, just something more like 50%, but since then, it’s obviously been a bit of – a bit activity on the other side of the block. So, I wonder whether that’s still your attention. And could you say it, could you say where the shells approach to plan to buy that 20% we talked about divesting, you probably won’t answer the second one but maybe the first one would be interesting.
And secondly on Kashagan, now we’ve got to the end of the long-slide process. Could you tell us how much the first phase of experimental phase finally caught?
Well, Claudio will answer you the second question about Kashagan. As far as potential divestment from our 70% stake in Mamba in Mozambique, let me just I knew that it very early days for us to even consider any possibility in this area. Now, it is true that we’ve been approached by almost every player in the industry who liked to be part of this new frontier for gas in Eastern Africa that’s true, we’re still in the exploration phase, we don’t really know what we have apart from the 30 bcf that we have been discovering in the last few months. And therefore whatever decision we would like to take this would be, not before I would probably say the end of this year because mostly of our exploration would be finished by the end of this year beginning of next year. On Kashagan, Claudio?
On Kashagan, on Kashagan, the right coast of the Kashagan for the primary phase in the range of $34 billion against $32.6 billion authorizing in 2008. So, the reason this increase of about $2 billion, a direct cost for the development without the G&A, probably about 4%, 5% essentially.
Any more questions from the floor? Probably not at the moment, so, maybe if there is question from the call, we could pass on to them now. (Operator Instructions) No questions from the call. More, from the floor.
Yes, good afternoon. Robert (inaudible). Few questions on the Gas & Power division. My first question is what do you think about the potential process of making available the spare capacity in the import pipelines? And if you can a little bit elaborate the effect of the impact of on the Gas & Power prices in the Italian market? And if this potentially impacts us in your target in the gas division, that’s my first question.
My second question is on the gas demander as well. You disclosed that 18% demand increase all over the period up to 2020, my question is many operators are saying that 2015 in the period 2012, 2015, the gas demand is very – would be very weak, so, I’m wondering if this – what the demand increase would be all over the period, the planning period.
Third question is on the E&P. And if you can disclose some data about the funding and development cost in Mozambique and if possible, if you have any, I understand that is, could be a bit early if you have any recovery ratio on Mozambique.
My final question is about the production target in E&P. Basically you are saying that 700,000 BOE is the additional production from new discoveries. If my mathematics are not wrong, basically I understand that 50% of it will be eroded by the pleasure rate, my question is if the – if you are considering something like a disposal of this deplete in fields, in special purpose companies just to you know, to eliminate the tail production? Thanks very much.
Many questions let me try to answer one then I would pass to my colleagues the others. Now, on gas demand, this 18% by 2015, what will happen to demand, now, to answer your question we should make some economic forecast in Europe. What we know is that the penetration of gas and is primary source of energy continues to grow.
Essentially in Europe, there is no way to make electricity than renewables and gas today. Nobody would ever think to build a nuclear power station or a coal fire power station. So, if you believe that European industrial activity would grow by 4% per annually, we would expect gas demand to grow more than that, well, to grow significantly. If you believe that Europe is going to be in stagnation until 2015, then gas demand would remain sluggish.
Our view is that demand for gas will grow not a lot but I think we gave you a number of by 2015, how many been there is more, something like 70 billion cubic meter, moving from 500 to 570 if I’m not wrong. So, that’s on the question about demand. Now on the first question, maybe Umberto, you want to answer.
Yeah, one of the article of the liberalization decree foresee the objective as to reduce cost for industrial customers, gas customer by increasing the level of input for of gas for Northern Europe. This is the objective of the article, and implies that we will see some decision about the binding the relations for their residential customer, particularly if you’re considering the situation of very rigid winter. Another aspect of this still has to be defined with the outreach condition, this gas will remain available and this has to be identified how that will be guaranteed to be at competitive, with competitive condition of market rules.
So, we expect that the government to continue on this approach and taking it quite rightly, a very cautious approach in order not to create distortion in the market. I have to say that I missed the second part of your question on this subject, if you could please briefly repeat it?
Yeah, the second part is, if this kind of a scenario will make some further pressure on margin, gas margins and if this scenario is included in your new targets in this 2012, 2015 plan?
Okay, thank you. Yes, it is considered because in our scenario we have defined a level of criticality of the markets continuing for the next two years with farther competition between spot price and the long-term price. Nevertheless, we are imagining a situation that will show some recovery of demand some tightening of the L&G market, that will reduce this price, therefore making less critical as it could look today, the fact that there will be more open circulation of gas also coming from the North European house.
For Mozambique and for finding and development costs, what we can say now for Mozambique we can just talk about exploration unit cost that has been very, very low, around $1. For the final development cost of our E&P division is for the full year plan $14.5 per barrel and for Mozambique we cannot say, we cannot talk about finding development cost because normally we put all the cost divided by the P1, so for Mozambique we don’t have yet the P1 research, so we just can’t talk about exploration of course.
For the second question about production, in the full year plan, we have about 40,000 barrels per day disposal, and so, it’s true, we are going to business some assets and may these assets managed mainly in the North Sea that is more or less what we’re going to do at the moment that is have been planned.
Alastair Syme – Citigroup
Hi, it’s Alastair Syme from Citi. Can I ask three inter-related questions on the downstream please? Firstly, if you look at previous cost, I think plans which would be largely directed to this business that it seems to have much impact on profitability. So, I was just wondering why you think you’re going to be able to retain cost savings this time around?
Secondly, what do you think will happen to capital employee across downstream both refining marketing and chemicals through the period. And thirdly, I wonder if you could put those together, the capital employed and the cost savings target in terms of our return on capital employee target?
Well, now of course, your questions are focusing on downstream. In fact the stories around R&M and chemicals are somewhat different, and they probably deserve different question. Let me first deal with the issue around chemicals. Now I will say if you worry about the story of our chemical business, and then will hand it over to Daniela will talk more about the future of the business.
Now the story of our chemical business is all around the fact that when we were 100% owned by the Italian government, we have received as a gift not really the kind of gift you would like to have, all, all the companies which went past in Italy, do with the chemical businesses. So, we received, I can say, really hundreds of plants all over the country, some of them closed, all of them are in seen deal, you know, that we have this bad company which is making in a TV clip of let’s say, the polluting the fields. And the ongoing ones went into polymer.
This business was if I may simplify you know, from my point of view, it was running systematically six or seven percentage points of EBIT below its competitors. As a result of being wrong locations, more plants you know, the fact that nobody has decided anything about that, they just arrived, okay.
As a result, when everything was fantastic, we were making some money. When everything was valued, we were losing a lot of money. And this has been true for many, many years, probably since the beginning. The whole strategy we had was less cut down this disaster, this was the idea. Now, let’s close plants, close pieces of plants, reduce, reduce and reduce.
Now, of course you can imagine how difficult it is in Italy to close down plants particularly in Southern Italy, because most of these plants are located in Cecile and Sardinia, which adds to the problem. And this strategy has been followed until let’s say, couple of years ago, when we decided that in order to go further we needed to have a different idea, because otherwise we would – we were stuck with this propitious problem.
Then we hired Daniela who has been – who is an expert and is bringing new fresh air to our thinking in chemicals. And he has been working on a plan which at least convinced me, I hope it will convince you as well. Well, it has been very convincing for me, which maybe, in five minutes you would like to?
Paolo, and thank you very much for teaching (ph) this situation so well. I think what Paolo was saying is that we didn’t decide to either chemical business in such shape that we have it today, so that’s the essence of it. So, we did a little something different from the past which is not fixing problem and efficiency but we need to reconfigure the business completely.
So, play on our strengths, we do strengths. We have critical mass, we have boot technologies, we have excellent reputation, so, just change the strategy and play on the added value product we can make and try to enlarge that path from 20% to 70%, 80%. So, this would be through JVs, going back to West Asian or Latin American markets following our customer base, which are developing their technology across the territory. So, this is the way that we would deploy the capital in future, green chemical project to replace obsolete, that’s what chemical size technology, geographical expansion.
So, we’re shaping a lot of portfolios. We will not throw away the 360 million we built on efficiency this is have to continue to be part of our plan because of the economics of the site where we are located. But we will build on that to make it more profitable in future. I hope I answer your question.
Let’s move into refining. And since most of your questions are around financial, we’ll ask Alessandro to answer.
Yes, as already anticipated during the presentation, we are committed over the next four years to recover profitability in R&M, and we have a target to recover more or less 400 million of additional margin over the next four years. What are the main most important action which supported this recovery.
As we have already stated that we refer in timely to organic moves in turn move in particular, leveraging own integration between our refinery plans, logistic, improving the logistic between the various plans that we have in particular in South of Italy. On savings in terms of energy costs, a lot of our initiatives are already ongoing and we expect to arrive to the end within the end of the year.
So, a significant portion of these savings, we expect to be able to achieve some of them already by the end of the year. So, predominantly, our internal moves and leveraging also on the technical knowhow that in particular hour people of the refiner or refining and marketing have and we are deploying these know how in order to improve the efficiency of our refinery plans. So, organic moves, cost savings, efficiency, and flexibility. These are the drivers on which we will refer in order to obtain the 400 million, recovery in margin.
John Rigby – UBS
Hi, it’s John Rigby from UBS. Three questions please. The first is just to wrap up on the discussion we’ve just been having on downstream. Obviously with the new government in place in Italy and some of the ambitions that they have for changes to the Italian economy, could you talk about whether that is help with some of these ongoing structural problems you’ve had with the downstream and the inability to restructure and whether that’s something that we should take on board?
The second is just to go back on SNAM, I’ve seen stories in the past and you never know what to believe and what not to believe. But discussion about whether there would be staged sales, part sales, you hold on to something, sell again, a little bit later on, part for cash, part for shares. Can you talk about you know, whether there is options in between spin-off and cash sale and what your thoughts are around that?
And then, lastly just on Mozambique, can you confirm that it is your intention that you’re handle your expectation that you’ll become operator of the unitized area of one and full and if indeed that’s the way it goes forward? Thanks.
On downstream and on the hopes that the down environment becomes takes us a doubt, and frankly well, I’m probably more used to Texas that retell it. But this country remains a country particularly the south of the country where employment, it is an issue, which does not mean that we cannot do things but we should be doing things in a very wise manner.
We are perceived to be too big and to reach to let’s say, not to create problems where we cut down employment and we do not offer alternative solutions. Now, all our planning – now I’m talking about chemicals but we could do the same thing on refining, all our plan is targeting shutting down production, losing money production and increasing production, probably not on an equal foot in terms of employment, in new production which are more profitable, which we use our technology abandon the old commodity products.
So, in R&M, now in R, forget about M, M is doing well now, better or worse, but we are always very positive. Of course, when the price of gas on in Italy is above €2 you can imagine that the Italian drivers, driver of place which is say it’s down, and therefore even marketing is suffering. But generally speaking, I believe in marketing, we are making more money than our competitors. So, the problem is around refining.
In refining, yes, we have a variable for which I’m very pessimistic in the long term, which is the refining margins in the Mediterranean, I frankly don’t see any reason why they should go back to $8, $9, $10, which we have seen three years ago, not 20 years ago. So, that is an area which I’m not expecting any good news. But the area of the differential between light crude and heavy crude which has been the – how can I say, the key around which any refining system has been built for 40 years, I mean, frankly there is no reason why this gap should not go back where it has been forever.
Let’s say the financial between light crude and every, crude today is what Angelo, $3. If there has been forever $10, but when the oil price was $60, $50, what then, now at $120, is $3? Now if you imagine our results, our results, with the financials, similar to what has been, you will see that our results are much, much better, then, let me add another point.
Now, every time that the cost of energy goes up and for us the cost of energy is the price of oil, it goes up. What happens is that we have in our reported results loss, but in our net result we have a profit because in our while the price of energy goes up and therefore the cost of producing gas goes up. The stock that we have creates a lot of value, now, of course you do not see this value because we are not yearly crediting the company but in fact, if we take into account, the growth in value of our stocks of today, this more than offset all the losses we have made in revive.
Now I’m not saying just say to make us happy because we are not happy, but just to give you how important are these two elements in our account. As for actions in terms of refinery, that is potential temporary or permanent closure of some refining capacity, in Italy, we do not exclude them at all, I don’t know if I’ve been answering to your question, Claudia Mozambique.
Mozambique, so, first I’d like to remember that before talking about operator-ship we have to unitize the area and once we have unitized the area, based on the gas in place, we are to agree a plan of development and the plan of development must be up to advisory. Then I’d like to give you additional elements. First, that we have a stake of 70% in the area four, the second that we are first operator in Africa, and third that we participate and we constructed eight trains of L&G in Africa already. So, we start from this position.
Okay, it’s a good starting point. Let me, SNAM, a few words about SNAM. Now, of course you are mentioning about potential combination between stock dividends, spin-off shares, of course there are all possibilities. Frankly, we are not there yet, we are not there yet, we of course – there are many ways to recognize the full value of SNAM shares in Italy.
My view is simple, the day after that we lose control of the company, we want to get out. We are not in the business of holding 5%, 10%, this is not a part of our business. And I would add a second point we would like to go out quick because we do not want to create the stock overhang on SNAM, we feel responsible for the well-being of SNAM shareholders, we have been bringing the company into the market.
We had been increasing the capital of the company, a couple of years ago, through the addition of ethyl gas and of storage (ph). And therefore we cannot forget SNAM shareholders which remain for us a worry that we want to – we do not want to have. So, yes, there are several possibilities no doubt about that.
Great. Perhaps, we could go to the call for questions from that and then return to the floor. There is a question from Mr. Andrea Scotty (ph) from Medubuck Milano (ph). Mr. Scotty, please.
Yes hello, can you hear me?
Yes, we can.
Yes, good afternoon everyone. I have a couple of questions. The first one, sorry again it’s on Mozambique. I was wondering if you see, if you perceive risk of an increase in the taxation in Mozambique. The second one is on the dividend during the latest call Mr. Scaroni clearly stated that an extraordinary dividend has to be excluded in the case of a cash deal on SNAM. I was wondering if a cash deal would materialize, is it possible to foresee a more generous dividend on 2012 dividend base? Thank you.
Mozambique again. No, I just remember that we signed a contract, APSA contract that’s start from respiration phase and also that is valid for the development phase. So, we don’t foresee any change in the physicality and we don’t have any (inaudible) on the sense, at the moment.
Now on dividend, you might remember that we stated a policy of dividend which was based on some parameters, probably not worthy for me to go back because I think it is well known by everybody. Now, this year 2012, now forget for a second SNAM and potentially GALP, but it is true that oil price even at our scenario of 90 is higher than the oil price of 70 on which our euro plus inflation was defined, that’s true. But we have to wait on the other side that our Libyan products has not yet where it was when this policy was stated.
This is somewhat an exceptional item. So let’s say our view would be that everything being equal, the dividend policy of €1.04 per share seems to us fairly correct and in line with our past and inline also with what our peer group is doing. Now when we move into what happens if we have a huge cash inflow from these potential sales of our non-core listed assets.
Now, I think I made quite clear the fact that if our company as it is heading to, continues to accelerate this growth and is even targeting 2.4 million barrel by 2021. I mean this will be the result of explorations, successful exploration, but also huge development plans which we’d require a strong balance sheet. So any change, potential change in our dividend policy after 2012, so 2010 onwards we’ll have as a NorthStar, our strategy in order to continue to grow our production following our successful exploration.
I think we can go back to the floor, yeah.
Theepan Jothilingam – Nomura
Hi good afternoon, Theepan Jothilingam from Nomura International. Just a couple of questions actually, when you look at your E&P portfolio and the company as it stands, increasingly you are transforming yourself into a global E&P business that it is very competitive, but I look at the portfolio and it still seems in terms of North America and the U.S. the same sphere and absence as those wanting to know whether you had any thoughts on whether you needed to add a position in North America.
And then Claudio, I was just wondering on exploration as well, whether you thought you had in the current portfolio the ability to deliver your targets or again do you need to add incremental acreage? And clearly you’ve had significant recent success in exploration, I was wondering to know whether there was any sort of internal changes that you’ve implemented within Eni that sort of creating these outstanding results?
Now, this is for you.
Yeah. So for North America, first we have a position in North America, we’re producing about 120,000 barrel per day. We operate 65% of our production. We have a strong respiration campaign in the future, in the Gulf of Mexico we’re going to drill in the next three years about 18 wells and we have an investment of €450 million in the full year plan.
So I think that we can say that we have a strong engagement in the U.S. We have also – it’s more participation in the (inaudible). It’s true that we’d like to increase our position there especially in the oil shale and we’re thinking about that. But always through an inorganic growth was starting from respiration assets. So that is one of the point that we’re elaborating.
The second question about the future if you are able to continue to produce the same kind of result in time of volume and quality, I think so in the next four years for the assets that we have in Indonesia in the Barents Sea, I remember that in the Barents Sea we have seven new prospects that we’re going to drill in the next three years. We have to drill eight wells, so we have more or less €300 million of investment, a little bit less.
So we have still a lot of potential and as I said during the presentation I think that our geological model is very strong and well assessed. So Norway is one very strong point with additional, additional potential and in Angola we’re going to drill additional eight wells in the south far so the block-15 or 6 where within that we can increase drastically the resources in this area. Indonesia, another big hub where we acquired blocks, we were going to acquire additional blocks and we have at least say five or six prospects to be drilled in the next couple of years. Australia, again where we have three blocks and we start exploration. We drilled the first two wells this year.
So I think that we can confirm our success and our efficiency and effectiveness in the next four years. We changed something, yes, we changed something some years ago. We tried to be more selective on the high-risk and high reward assets. We tried to be more focused on the area where we had very strong knowledge of the geological model and we increased the share and the investment in the near fields.
So we create more near field, the investment in exploration to assure big grant positive results. And we have been more selective, reducing the big target, Irish target that has been the change that we made. We also changed some part of our organization and we gave more focus on the exploration unit abroad and additional control of the geological model centralized. So we changed something that is…
Very good, few more questions.
Mark Bloomfield – Deutsche Bank
Hi it’s Mark Bloomfield from Deutsche Bank, couple of questions please. Just following on exploration, just wondered how much of your 32 billion barrel resource base is attributable to risk exploration. And of that maybe you could give us a rough indication of how much is represented by Mozambique.
And second point coming onto Gas and Power profitability, I think sitting here a year ago you talked about a 4.2 billion adjusted EBITDA target for 2014. I appreciate there is a lot of uncertainty going forwards, but reflecting SNAM, reflecting your recent contract renegotiations, perhaps you could give us some indication of where you expect normalized EBITDA to be in 2015? Thanks.
So I start first with talking about the resources. When we’re talking about 32 million on our resources, we have inside 7.1 billion P1 then we have 6.5 P2 and 3.5 P3 and additional 6.1 contingent resources. So we are talking about resource that we have already discovered. So we have already discovered, we have already tested wells and feasibility study until the P3 and contingent and we have at the end additional 8.9 billion or 9 billion of additional (inaudible) resources. I mean there is a risk aspiration that is the situation. Mozambique as a – as Mozambique inside, this is $5.4 billion barrel, so that is the complete answer.
I’m working hard trying to give you an answer for the question about Gas & Power, yes you are right. We used to give 4.2 of which the SNAM part was roughly two, okay. So in fact this 4.2 was roughly two excluding SNAM, okay. Now today as you said to give a guidance in gas is one of the most difficult thing you can do. This guidance has become extremely difficult because the market is, has become very volatile and it’s extremely difficult. If we were to give a number, but a number which please consider that numbers today in the gas market are much less solid of the numbers we have been giving in the past. We will consider 2015 something around 20%, 25% lower than the 2 billion we gave in normal market conditions. Do I make myself clear on that?
Mark Bloomfield – Deutsche Bank
Sorry, so can I ask a follow-up to that question please? I mean in gas marketing specifically, I just wondered how much of the benefits of the contract renegotiations with Gazprom and Sonatrach you expect to hold on to and how much of that you think will be passed on to your customers to try and win market share specifically referring back to your business-to-business gross targets?
To answer this question of yours is even more difficult. No, I explain you why, because it’s, first of all I cannot give you precise number on contracts, this will be breaching all confidential agreements we have. But apart from that these three contracts, so that we have been renegotiating in the last couple of years and therefore with the Libyan NOC, with the Sonatrach and with the Gazprom have three things in common. First of all price has been lowered. Now, when I mean price, I mean P0, okay, then we get back to this P0.
The second, we have been reducing the take-or-pay mechanism, so the take-or-pay instead of clicking in at 80 clicks in at 60. So we have some advantage in the sense the volumes can go down without hitting us through the take-or-pay mechanism. And thirdly, which in my view is the most important of all, the most important of all we can renegotiate. Instead of having the every three as a negotiation which was typical of this long-term contracts, remember this long-term contracts come from a very long past, it has been the basis of this business for the last 50 years.
So we can renegotiate and renegotiate for me is the most important thing both sides, because this market is extremely volatile. Now, let me go back to the P0 and answering you why this question of yours is very impossible, it’s very difficult to answer. P0 means the price at which you start linking the number to the oil price, okay. So suppose that tomorrow, the oil price goes to $50 make an example, our price for gas will go down dramatically and our – the price we pay to our suppliers I mean would go down dramatically and our long-term oil linked gas price would be super competitive to any spot price, okay. Suppose on the opposite the oil price goes to $200, our P0 is lower than it used to be, but a $200 will go very much up, it will compete with spot gas, it would be extremely expensive.
So it is hard to answer your question because we don’t know exactly where oil price goes and of course when I look at that from any, I have a kind of natural hedge in the sense that these two, if the oil price goes to $200 this is the news for my friend Umberto, but my friend Claudio would be very happy and the opposite (inaudible), friend.
No, you see what I mean, so that’s the reason why it’s very difficult to answer your question. I could answer your question if you tell please give me your answer at oil price of $80, then I can give you an answer. I’m not sure I want to give you an answer, but I have a number in my head and I can tell you if our gas would be competitive or not at that time. Do I make myself clear? Okay.
Jason Kenney – Santander
Hi there, it’s Jason Kenney from Santander. So I recall in the past that you had an agreement with Gazprom whereby on your entry into Russia and then investing in Russia, you may actually then be able to sell Gazprom part of your international portfolio in return for investing in Russia. I just wondered if that was still the case and if so, if Gazprom is prioritized particular positions in your portfolio then I’d like to join you then. And then secondly a small clarification as to whether you’re interested in Angolan Refining which I think has been muted in the press.
Let me resume this old story about our known – so called known Russian transactions. When we bought the stake into what we call (inaudible) here today that these recalls, that I would call it synched that is our assets in the Yamal, Peninsula, the one the cloud is being describing to you in process and we start production very soon etcetera. We paid the whole thing which if I’m not wrong, our equity was 1.5 billion barrels made up of condensates in gas for a total of $1 billion.
Jason Kenney – Santander
$1.2 billion, so we bought for $1.2 billion the 1.5 billion barrels in the Yamal, Peninsula discovered but to be developed. As part of the agreement we agreed that we would have let Gazprom to buy half of the value that is $600 million in assets upstream and downstream outside of Russia, okay. So this was the agreement.
This was signed in 2006 or 2007, 2007. Since then, we have been offering to Gazprom several alternatives and so far we didn’t reach any conclusion. The reason is the complexity of our business, because practically all our upstream activities, we did not only the agreement of the host country of the oil country, otherwise we simply cannot do it, but normally everyone has a premature right.
So as soon as we say, but if we want to sell it would our partners buy, they say, yes, yes, yes and so we have to pullback, okay. In downstream it’s somewhat the same thing, some refineries allow us, we are partners. So let’s say so far we have not reached any conclusion, but just to answer your question precisely yes, we have an agreement, yes, we want to fulfill it. It is a very small thing, because you understand $600 million of assets is a minute portion of our portfolio either in upstream or in downstream Angola…
Refinery. So for refinery in Angola we signed two years ago a framework agreement, a larger framework agreement with (inaudible) concerning gas upstream asset, oil upstream asset and inside this agreement there is also the refinery in thermal studies and feasibility studies and the – and that’s what we’re doing and that what has been reported in the newspaper. So there is not yet a project sanctioned, there is just discussion and feasibility study ongoing.
Neill Morton – Berenberg
It’s Neill Morton with Berenberg. I had an upstream question on Kazakhstan. I’m looking at the slide, can you just confirm the 2021 production guidance does not include a third phase of Karachaganak or a second phase of Kashagan. And then just secondly on Kashagan phase-II what is your attitude towards that and it rumors that some of the other IOCs are looking to head for the exit. Thank you.
Well on the long-term production 2021 there is not a second phase and there is a risk portion of the third phase of Karachaganak also because now we finalize of our agreement with a republic and we’re studying the third phase and the republic is willing to go ahead with the third phase. So we think that in maybe less or couple of years we will be able to sanction the project. So we’re quite confident about the contribution in the long-term.
For the second question, I cannot answer anything about rumors. I don’t know anything about rumors. We’re finalizing the negotiation demanded for and I immediately after we’re going to start discussing about the phase-II and talking about anywhere under pressure and focus on the first production.
One more question here.
Colin Smith – BTB Capital
Thank you, it’s Colin Smith from BTB Capital. I’ve got two questions. First one was just if you could tell us where things stand on south stream now, because you didn’t mention that’s on the presentation. And the second question was you identify the right to renegotiate is being the important component of the agreements that you’ve reached with the three pipeline suppliers that you’ve reached agreement, given you had the three year price causes I think with them anyway, could you just elaborate a little bit on what the right to renegotiate means it’s different from what you had before? Thank you.
Well, let me answer the first of the second question which is very easy. We ask and agreed what we call a joker in the agreement that is the agreement continues to be the same, the same old agreement, every three years the parties get together and negotiate prices. But we have a joker that we can play anytime if we want to renegotiate within the three years period. So for example, take the example of the last deal we signed with Gazprom, we could, beginning of 2013 that these one year from now start a new renegotiation phase if prices are very different from – for prices or whatever price we have in Europe.
So we have an opportunity – I have to tell you frankly that they could have any kind of agreement on price and on the take-or-pay, but without the joker it would not assigned, because the level of uncertainty is so high that it becomes a very – I mean a threat for everybody, for us as the seller and for then as a suppliers. So I think it is fair to recognize that this market is totally different from what we have seen for many years.
Now I’ve been in Huston last week to speak about gas and all these kinds of things, I mean every time I think that the same molecule of gas is worth $2.2 per million within the U.S., 10 in Europe and maybe 11 or 12 for long-term oil link contracts and 16 or 17 in Japan. The same thing, now this, I mean this scenario is so awkward and strange that nobody really knows what will happen. What I can – I’m sure that will not last forever this differential and I could add a $2.22, a calorie coming from a gas in the U.S. cost one-eighth of a calorie coming from oil, one-eighth, for how long this absurd differential will go into asset. Therefore we have added this clause which allows us to renegotiate.
Now on South Stream, it is in simple terms why we are in favor of South Stream. We are in favor of South Stream essentially for three reasons. The first reason is being a major player in the European gas market, we need to ensure to our customer reliability and security of supply. Now, we have seen too many times that problems arising from transit countries jeopardize the security and supply to our customers.
Now, I prefer to have a pipeline which cross the Black Sea rather than a pipeline can cross a transit country, essentially this is the first reason. The second reason is that the whole mechanism which is at the origin of these pipelines make it normally an investment, which is fairly easy to finance through non-recourse financing from banks, because it is guaranteed by a shipper pay from the supplier and they take-or-pay by the customer. And therefore the amount of equity involved with normally is limited.
And third, I mean I cannot forget that Saipem is the candidate to build this pipeline. It has built Blue Stream which is crossing the same Black Sea, it has I believe, probably the only one ship ready to make direction, the deposing, they’re laying down on the pipes and therefore we have an additional – what is a very reliable supplier to Gazprom, because it has been the North Stream as you may remember. So let’s say in total I see several interest for us to follow this project. We are not at the end, but we are confident about the future of this project.
It seems that there are no more questions from the floor. I think that’s correct. Operator, could you confirm that there are no more questions from the call?
No more question from the call.
Great, thank you. So that’s the end of our strategy presentation.
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