Good afternoon, ladies and gentlemen, and welcome to Eni's 2014 fourth quarter results conference call, hosted by Claudio Descalzi, Chief Executive Officer, and Massimo Mondazzi, Chief Financial and Risk Management Officer. For the duration of the 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 hosts to begin today's conference. Thank you.
Good afternoon, and welcome to our fourth quarter result presentation. 2014 was a year of great change in Eni. In many, we started a deep review of our cost structure and accelerated the execution of strategic programs. This action allow us to beat our cash flow growth targets, lower our leverage, bring gas and power back to profit, progress the turnaround of R&M and chemicals. The first step of the new action plan was to change the organization from a divisional company to a fully integrated one in order to enhance flexibility and efficiency. The new simplified organization brought immediate benefits in terms of speeding up processes, reallocating staff, and allowing G&A cost reduction of EUR 250 million. Material results have been achieved in the different businesses.
In upstream, we continue to obtain outstanding exploration results with 900 million barrel of discoveries, mainly in Congo, Ecuador, Egypt, and Ghana, with a competitive exploration cost of around $2 per barrel. These new resources, mainly liquid, are conventional and can be developed in phases using existing facilities with limited upfront investment. As a result, the project has strong economics, also in the current weak scenario. We acquire new blocks in the Caspian region, West Africa, and the Far East, reloading our asset base with an additional 100,000 square kilometers of new exploration acreage. We fast-tracked the startups of recent discoveries in Angola, in Egypt, and in Congo, with an overall year-end gross production of 60,000 barrel per day of oil. Thanks to the contribution of new projects and the strict control of operations, we fully met the production target.
Finally, also this year, the organic resource replacement ratio was in excess of 110%. In mid-downstream, we proceed with major gas renegotiation to align the supplies to the hub's reference, bringing forward gas and power's breakeven by a year and accelerating recovery in the take-or-pay. We reduced losses in chemicals and R&M by cutting 30% of our refining capacity and focusing the portfolio with the start up of the green plant in Porto Torres, and then with the agreement on the conversion of Gela refinery. Finally, we collected EUR 3.7 billion from disposals, mainly from the sale of Russian assets, the recent exit from South Stream, and the dilution of Gas Natural. Talking about 2014 result, I would like to give a special focus on project development, where the changes we implemented in 2012 have delivered their first result. We have based our development structure on three key pillars.
First, we take the role of lead contractor in all phases of development, from engineering to commissioning, directly managing all the different development packages. Second, most of the development are split in different phases, mitigating operational risks, bringing forward cost recovery, and finally reducing financial exposure. Third, we maximize the use of modularization and standardization, exploiting the existing facilities and equipment already on the market. The most tangible result of this new model are the two recent startups in West Africa. In Angola, in Block 15/06, where we have found more than 3 billion barrel of resources in place, the startup was reached in less than 4 years after the declaration of commercial discovery, an impressive result for a deep water project. The performance of this field is better than expected, currently producing about 45,000 barrel per day.
Every 6 to 8 months, we plan to add a producing cluster to existing hubs in order to reach 200,000 barrel per day in 2018, after the startup of the east hub. In Congo, in the Marine XII block, we have discovered 3.5 billion barrel resources in place to be developed in different clusters. The first of these has been the Nené Marine discovery, where we were able to fast-track the production startup only 9 months after the FID through the reconfiguration of available platforms and maximizing the use of existing network and facilities. The huge discovery has started with the early production and will be developed in phases to reach a plateau of around 120,000 barrels per day in the next 5 years. We are adopting the same approach to other major discoveries in Angola, Ghana, Egypt, and Ecuador. Talking about cash result.
Despite the drop in oil prices in the last quarter, we have beaten our cash target with a cash flow from operation of more than EUR 15 billion. This represents a 40% increase with respect to 2013, well in advance of our original plan. It was reached mainly through EUR 2.2 billion coming from cost and production efficiency in the renegotiation of gas contracts and the downstream turnaround, and a working capital improvement of EUR 1.9 billion. The outstanding cash generation from operations and disposals has entirely funded our CapEx and distribution policy, positively impacting also the reduction of leverage, which now stands at 22% from last year, 25%. Now some preliminary elements for 2015. In order to better cope with the current price scenario, we continue to implement and reinforce the cost efficiency program that we started in May 2014.
Our expectation is to have EUR 2.5 billion of optimization coming from CapEx, OpEx, and G&A costs. The EUR 2.5 billion are split as follows. In term of overall CapEx, we expect around EUR 2 billion of reduction equivalent to 14% of 2014 CapEx at a constant euro-dollar exchange rate coming from: the first 20% due to the reduction in non-upstream businesses as a result of the recent rightsizing. Second 30% due to the reduction in exploration spending, where we will continue to focus more on near-field and appraiser activities, reducing investments in frontier exploration areas where we have been successful in the recent past.
Lastly, 50% from the reduction in upstream spending due to a rephasing of complex projects, focusing on simpler development with shortened time to market and the overall revision of the existing supply chain, where we see signs of cost reduction for some items in the order of 20%-30%. Additional cost revisions in the following years will be presented in the full-year plan strategy presentation next month. In terms of OpEx, we expect in 2015 a reduction of EUR 300 million coming from optimization activity, substantially from contract revision, rescheduling of non-mandatory activities, and energy feedstock prices and logistics costs. Our total cost per barrel will be reduced by 14%, while we still confirm a production growth rate of 3% at price parity. As a final point, from 2015, G&A cost will be reduced by about EUR 500 million, doubling what we already saved in 2014.
Now I will hand over to Massimo for a brief overview of the results.
Thank you, Claudio. For Q4 2014, the adjusted operating profit was EUR 2.3 billion, down 34% versus the same period last year. This was mainly due to the fall in Brent, which averaged $76 per barrel in the quarter. The major impact was on E&P, where the benefit of EUR 350 million of industrial improvement cost and volumes was more than offset by the scenario impact that accounted for EUR 1.6 billion. On a full year basis, the operating result is down EUR 1.1 billion due to the reduction of EUR 3.1 billion for E&P, mainly due to the negative oil and gas prices effects, while all the other businesses delivered a EUR 2 billion improvement in performance. The adjusted net profit for the quarter amounted to EUR 464 million.
The year-on-year decline is principally due, other than the aforementioned scenario, the negative fair value contribution of our remaining stakes in Galp and Snam, evaluated at the share prices of 31st of December 2014. Since then, these prices have moved up significantly, and if we had to adjust the valuation to today's levels, the reported loss would have been reduced to around one half. The fair value valuation also tax rate that was 15 percentage points above the full quarter 2013. Net of this effect, the tax rate would have been in line with the guidance. For the E&P sector, on a full year basis, net of the effect of the sale of Russian assets, production was slightly higher than in 2013.
Looking at fourth quarter versus third quarter, the increase is largely attributable to better performance and recovery from lower production in the third quarter related to maintenance, and the contribution of new startups, such as in Angola Block 15/06, Abo in Nigeria, Abu Rudeis and Emry Deep in Egypt, Nené in Congo, and finally, the PSA effects that accounting for 14,000 boe per day. Operating profit in the last quarter was affected by the decline in crude oil and gas prices. It was only partially offset by the weakening euro. The overall negative effect of the scenario is estimated at EUR 1.6 billion versus the fourth quarter last year, and more than EUR 1.1 billion versus the third quarter. The entire reduction in operating profit between third quarter and fourth quarter 2014 is explained by the scenario effect, as better operating performance was offset by higher exploration cost of around EUR 100 million.
Turning to reserve replacement, we confirm our historical track record with a ratio of 112% last year. Around 20% of the promotions were related to new discoveries and extension, mainly in West Africa, in Ghana and Congo and Angola, and Far East in Indonesia. The remaining 80% related to positive revisions of reserves in already proven fields. Among the revisions, the price effect on PSA-related reserves contributed a limited 30 million boe. Since 2010, Eni has consistently been replacing its production organically with an average rate of 127%. Turning to gas and power, adjusted operating profit was a positive EUR 108 million, thanks to the continuous improvement of the underlying performance and the benefit of renegotiations concluded in the year. The full year result was EUR 310 million, an increase of almost EUR 1 billion over 2013.
Even excluding one-off effects and retroactive elements, this result represents a material operating performance improvement of around EUR 600 million. On a cash basis, the take-or-pay recovery amounted to EUR 650 million, leaving a residual amount of EUR 1.3 billion at the end of 2014, of which around EUR 0.4 billion already accrued in late 2014 will be cashed in at the beginning of 2015. Refining and marketing showed a marked improvement both sequentially and year-on-year, with an adjusted operating profit of EUR 192 million achieved in fourth quarter 2014. It is the second consecutive quarter of positive results, and it confirms that this business is already profitable on an adjusted basis at the current scenario. This is the consequence of our progress in reducing capacity to counterbalance the decline of demand, that in 2014 was 1% lower than the previous year.
Capacity reductions were achieved at the Venice and Gela plants, further operating announcements took place at the remaining place. Overall, our capacity utilization rate in the quarter was up to 73%, an improvement of 12 percentage points versus fourth quarter of last year, driving down the break-even EBITDA margin of our refineries below $6 per barrel. Finally, the improved cash position helped to lower the leverage to 22%, even after the payment of EUR 4.4 billion in dividends and buyback, which represents the 10% increase in our distribution policy versus the previous year. In detail, the EUR 15.1 billion of operating cash flow with a 40% growth versus 2013 marked our best performance since 2008.
The EUR 4.1 billion increase versus 2013 was due to an improved overall performance, including EUR 1.9 billion recovery in working capital, mainly related to the reduction in E&P credits and the reduction in take-or-pay position. Disposal of almost EUR 3.7 billion were completed in the year, including the collection of EUR 350 million for South Stream. CapEx was capped at EUR 12.6 billion, 5% lower than 2013, in line with our guidance. Net borrowings were down EUR 1.3 billion, lowering our leverage to its lowest level since 2006. Now, I will hand over to Claudio for final conclusions.
Thanks, Massimo. To conclude, 2014 was a year of important achievements for Eni, where we deliver remarkable economic and financial results. Even taking into account the weaker price environment, our cash flow from operation was over EUR 15 billion, a 40% increase over 2013. This very positive cash generation, including cash from disposals, has covered our needs with regard to CapEx and distribution policy, and also contributed to reducing the leverage. Based on this result, I am pleased to announce that the 2014 final dividend proposal is confirmed at EUR 0.56 per share. Thank you very much for your attention. Now we are glad to take your questions.
Ladies and gentlemen, the Q&A session is now open. I would like to remind you that if you want to register for your questions, please press star 1. To cancel the reservation, press star 2. Thank you. This question comes from Mr. Oswald Clint from Bernstein. Mr. Oswald Clint, please.
Yes, good afternoon. Thank you. Claudio, I really want to just talk about 2009. Obviously, similar environment, through the year, some of your businesses within the Eni group became a lot weaker, then by October that year, the board decided to reduce the level of dividend. Can you talk about whether you see Eni as in a better or worse position today, going through 2015, as it kind of talks about the dividend level for 2015, please? Then maybe a second question, maybe for Massimo. I am just curious about the gas and power business. I know 60% of the volumes have been renegotiated to hub link.
On the 40% remaining, which is oil linked, is the price of that at the moment, is it actually low enough or sufficiently low enough to start generating a profit as you import that and sell it through Italy and parts of Europe? Thank you.
Well, thank you very much for your question. I think that this comparison between 2009 and 2014 is very interesting. I'm sorry that I cannot elaborate further on that, because that is a part of our presentation in March, our strategy presentation. I cannot say. I'm not in a position to anticipate anything. In March, we are going to elaborate and make comparisons. In any case, I think that we are in a strong position. We are in a strong position, but the dividend policy is something that is related to board decisions, so I cannot anticipate anything.
Regarding gas and power, it's Marco. You don't see in these results any benefit from the drop in oil for two reasons. First, there's a time lag, which on average on these contracts is nine months between when the price changes and the effect is felt through on the gas contracts. Also, we have a number of sales contracts that are also oil indexed, so they fluctuate together when the drop will come.
Okay. Thank you both.
Next question comes from Mr. Theepan Jothilingam from Nomura International. Mr. Jothilingam, please.
Hi. Good afternoon, gentlemen. I just wanted to come back to your guidance on CapEx. Could you just re-clarify what the explicit number on CapEx is for 2015, on a stable sort of euro environment to last year? Secondly, coming back to, you talked about the reductions. I was interested in the 50% of that reduction being rephasing in complex projects. Could you maybe clarify again what projects you've deferred spend on for this year? Secondly, on cash flow and working capital release, significant release in the second half of the year. You've talked about the reduction in the take-or-pay commitments. Again, could you clarify what you expect at current prices in terms of working capital release for 2015? Thank you.
CapEx. I can repeat that our expectation, our plan, is to have about EUR 2 billion of CapEx reduction. That is practically equivalent to 14% reduction with respect to 2014. We are in a range of about EUR 12 point something billion of total investment. As I said, we have different chapters with different items. We have a 20% reduction of this 2 billion due to non upstream CapEx, practically in R&M and chemicals.
We have a 30% reduction in exploration, that is quite clear because we have been so successful in the last six years, we collected about 10 billion barrels of resources, now we want to be more focused on the short-term value, that means to work around our existing fields and our existing facility to be able, like we did this year, to have good exploration results and immediately tie into our existing fields to shorten the time to market. Going to the remaining 50%, that is the CapEx project. Without now telling exactly the name of the project, I refer to a more big and complex project that fortunately we already phased in different phases of development. We are able to reduce and postpone and move this CapEx and reduce amount of CapEx to a faster project.
We have this flexibility because we discover a lot of good oil in West Africa or in Egypt. I'm talking about Angola, I'm talking about Congo, where we can, in a very short time, this last year, we just had a nine months of time to market to develop and create cash flow. We have the tail plan, and that doesn't imply any impact on the foreign plan growth rate, and also is not impacting the long-term one. I think that during the strategy, we will be able to explain in more detail what we plan to do. We have to consider that half of this 30% or 40% of this remaining CapEx reduction is due to contract renegotiation.
As what we experienced in the recent past, in the last four, five months, that we were able to renew contracts, especially on the rig, on the services contract of about between 15% and 35%. That is already part of something that we already acquired that is a quite important result, and that is why also the reason why we can reach the EUR 2 billion of cost reduction.
Okay. Theepan, Massimo speaking. I'll try to give you some more color about the working capital movement and the expectation as far as 2015. You have seen from the balance sheet that the full year contribution working capital to the cash has been EUR 3.1 billion. That means EUR 2.6 billion additional contribution versus 2013. I would like to say that the more direct way to look at this number is to, I would say, eliminate the gross up effect due to the write down of stocks that definitely occur at the end of 2014 because of the price. This effect accounted for EUR 0.7. I mean, the more direct way to read the number is to increase the result contribution to the cash from operation of 2014 by EUR 700 million, reducing the working capital contribution for the same amount.
It means that I'm back to the EUR 1.9 billion I just commented together with Claudio, all along our presentation. Let me now elaborate a little bit more about this EUR 1.9. The major contribution to this EUR 1.9 definitely has been the take or pay. Take or pay contributed EUR 700 million in 2014 versus a cash absorption of EUR 200 million in 2014. In 2013, sorry. It means an additional contribution of around EUR 900 million. At the end of 2014, the stock in take or pay amounted to EUR 1.3 billion. That is already commented, take into consideration EUR 400 million already accrued in 2014. That will be cashed in at the beginning of 2015. On top of this, we expect an additional cash-in in 2015 of around EUR 400 million. It means that overall in 2015, we expect EUR 800 million in contribution in term of cash.
The second big contributor has been the reduction in overdue NWC, mainly in Egypt. You remember that we had EUR 1.5 billion overdue in Egypt for the long of 2014. This number now has been reduced to around EUR 950 million, thanks to the latest payment received by the Egyptian government in December 2014. This remaining amount of EUR 150 million, the expectations are to, I would say, to reduce even more this amount in 2015, and we are keeping on working closely together with the Egyptian authorities in order to find out the best way to speed up at least a significant part of reduction in 2015. Third big contribution has been the stock in oil. Thanks to the reduction in the refinery capacity already achieved, I'm referring to the 30%, we have been in a position to reduce our oil stock.
This accounted for EUR 270 million cash because of the disposal in 2014. Definitely expect an additional disposition in 2015 and 2016 while we are targeting the further decrease in capacity from 30% to 50%. Finally, the retail gas and power had a significant, I would say, reduction in overdue that has been mature in 2014. I'm talking about a number that will be in the range of EUR 200 million. These are the, I would say, the elements that explain the result in 2014 and main expectation in 2015.
Okay, perfect. Just the final question, what do you see gearing at year end? Lots of moving parts, but at $60, do you see gearing flat, up or down?
Again, I'm referring what Claudio has already said. Everything about the financial projection as far as 2015, sorry, but we elaborate a bit more on this during our strategy presentation in March.
Okay. Thank you very much.
Okay.
Next question comes from Mr. Nitin Sharma from JP Morgan. Mr. Sharma, please.
Afternoon, gentlemen. Two questions. First one on Mozambique. I think you've indicated in the past that further sale of stake in Area 4 is possible. My question is: Is this still on agenda given the recent oil price pullback and weaker Asian appetite for deals? That's the first one. The second one on gas marketing. Performance in Q4 2014, both have been ahead of guidance. You also mentioned that you've completed the planned contract renegotiations, or substantially completed those renegotiations. Therefore, is it fair to assume a year-on-year improvement in operating earnings of this business in 2015? Thank you.
Okay. The first question, yes, Mozambique is still in our agenda. The 10% is still in our agenda.
It's Marco. Regarding guidance for gas and power, as Massimo said, in 2014, there's some retroactive elements. The way we look at the business, we put the take-or-pay contracts and logistics together. In 2014, excluding the retroactive elements, the combination of take-or-pay and logistics is still not positive. The result is due to the performance on what we call value-added segments, which is LNG, power, and trading. Looking ahead, we have avoided arbitration with Statoil. We've exited arbitration with Statoil. We've avoided arbitration with Sonatrach and Gazprom. We are still in arbitration with GasTerra. We give the same guidance we gave last year, which is that assuming we successfully close the GasTerra arbitration in 2015, we are at breakeven. However, we also confirm the guidance that in 2016, regardless of this arbitration, we will be in a structural breakeven position.
Thank you. Thanks.
Next question comes from Mr. Martijn Rats from Morgan Stanley. Mr. Rats, please.
Hi. Hello. There have been some press reports about the potential sale of the gas and power division, or at least some sort of disposal IPO. I was wondering if you could comment on those. In the same sort of train of thought, if you could update us on your latest thought on the Saipem sale.
The first question is about gas and power. That, we don't like to comment on
Rumors.
Rumors or speculation on the press. What I can say, and repeat what I said during the strategy presentation in July, we consider, first of all, the possibility to give more value to our retail gas. We are not talking about gas and power, first of all. We really want to give more value to our retail gas. That is a very strong segment. We have 10 million clients. It's a very large one. It's not just in Italy, but also in Europe. We think that a specialized structure, because that is a specialized business, quite far from our core business, can be more value. That is something that is under evaluation. There are different possible options, we never talk about this option, and we never talk exactly about any plan. At the moment, that is just rumors. Saipem.
Saipem, I think we have two main objectives for Saipem. The first one, because we are the most important shareholders, is to really improve the value of Saipem. That is a very good company now. It's doing very well. It's in our interest to improve the stock value of the company, and that is our first priority. The second priority, because we are also the lender, and we give money to Saipem, is to reduce our debt or reconsolidate its debt. That represents about 32%. That are the two main options. We said a few months ago that we suspended what we are doing because of the market is very volatile, and we prefer to have a stable situation to go ahead. It's clear that meanwhile, we confirm our strong support to Saipem.
Okay, thank you.
Next question comes from Mr. Iain Reid from BMO. Mr. Reid, please.
Yeah. Hi, gentlemen. A couple questions, please.
Sorry, can you talk aloud because we can't hear you? Sorry.
How's that, Claudio? Better?
Not big improvement, but we try.
Yeah. Okay. All right. Sorry, I'll pick up.
Now it's fine. Now is okay.
I'll pick up the handset.
Yeah. I wondered if you could just update us on your oil price sensitivity for earnings and cash flow per dollar or per $10 or so. Obviously we've seen a big differential from what you were guiding to a few months ago. Maybe secondly, I heard you say that you're more confident about the dividend in this kind of iteration of Eni. I just wondered if you could update us on what you think about the share buyback at current oil price levels.
Okay. Iain, just to give you some flavor about sensitivities. In terms of Brent, our esteem is that every dollar, I would say minus $1, for example, means on the EBIT adjusted at the group level around minus or plus EUR 280 million. In terms of net result, is in the range of EUR 140 million, more or less the same amount as you refer to the cash flow. I don't remember, Ian, if you mentioned also the request to have sensitivity on refining margin or exchange rate, by the way, I give you anyway this quick number. In terms of margin as far as refinery, in terms of EBIT adjusted, $1 means EUR 150 million difference. In terms of net result, EUR 100 million, the same for the free cash flow. In terms of exchange rate, our metric is EUR 0.05 in terms of exchange rate.
EUR 0.05 means around EUR 280 million at the EBIT level, EUR 100 million at the level of net adjusted result, a bit less in terms of free cash flow, in the range of EUR 60 million because of the compensation of CapEx.
Thank you very much. Ian, thank you for the opportunity. I'd like to clarify what I said before. I said that I don't want to talk about dividend because the subject will be treated and discussed during our strategy presentation. I never say that I'm confident or not confident. I say that I don't talk, or I cannot talk now about dividend. Just to be clear, thank you for the question.
The buyback is.
The buyback is the same.
Really? Okay. Have you renewed the mandate for the buyback, or when do you have to renew it again?
In May.
In May. Okay. All right. Thank you, guys.
Next question comes from Mr. Thomas Adolff from Credit Suisse. Mr. Adolff, please.
Hi, guys. A couple of questions, please, as well. Firstly, on CapEx again, upstream specifically. You gave a bit of color on where the cut is coming from exploration and some of the rescheduling, rephasing of the larger projects, which makes sense. Can you perhaps also comment whether you have trimmed some of the base CapEx? Base CapEx sometimes is based on a two-year payout ratio according to some of your peers, and the current oil price environment doesn't justify that. If you have, what sort of impact that may have on portfolio decline rate? The other question I had was on Mozambique. I wondered whether your CapEx guidance for this year assumes the FID to be taken on both the floating and the onshore, and whether you have signed non-binding offtake agreements or HOAs or whatever you want to call it. Thank you.
Thank you. First on the CapEx. When you talk a CapEx base, I think that you're talking about the production optimization or CapEx or what we spent on the existing field to maintain production. That is something that we didn't reduce because that has very fast recoverability, and that's very high internal rate of return. That remain our base CapEx. That is also one of the elements, our strong element to fight depletion. That is not part of the yearly reduction for 2015.
Mozambique. Well, we are progressing very well on both straddling and non-straddling reservoirs. In particular for Coral, the non-straddling reservoirs, the EPC tender is ongoing with a major consortia, and we are expecting to receive the offers by the end of May. In addition to that, as you probably remember during last call, we mentioned the roadmap to FID. Well, we achieved the first three out of four steps in the submission of the plan of development. Just a few days ago, we completed also the process for the environmental impact assessment, which is a very important step for the approval of the POD. Certainly, we do see the FID around mid-2015. About the gas, we are-
Hi, Thomas. It's Marco. On the commercial discussions, I would say we're in advanced talks with a few very interested parties
Our aim is to agree key terms in the next few months. I would like to add that even in the current low oil price environment, the appetite for our project remains very high because of its geography, its size, and I think buyers see it as a way to diversify risk in their portfolio.
Thank you. Can I just quickly follow up on Mozambique on the onshore side? Presumably the mid-2015 FID is linked to the floating. On the onshore side, do you expect intent to submit the development plan to the government separate from Anadarko or jointly?
Well, talking about the onshore. First of all, as you know, at the end of 2014, the Mozambique authorities issued the decree law, which is the legal, fiscal, administrative framework to implement the project. This is a very good move from the Mozambique side. As part of this decree law, we have the possibility to run independently from, but in coordination with Anadarko, the first phase for 10 million ton per year. For this project, again, all the tenders are ongoing. The EPC tender for the offshore plant and the tenders for the subsea systems. We are planning to submit in the next few weeks also the plan of development. All activities are on track.
Okay. Thank you very much.
Next question come from Ms. Lydia Rainforth from Barclays. Ms. Rainforth, please.
Thank you. Good afternoon. If I could go back to the chart on page five around the cost data, could I just ask you to clarify for me what unit that's based on? Is it your own operated production or is it as the entire production? Partly linked to that, what are you assuming in terms of cost reduction on your non-operated production side?
That is our equity production.
Okay, within the cost reduction.
Yes, equity production, our interest.
Okay. Within that, what are you assuming for cost reductions from your non-operated production side? I'm assuming that most of that cost reduction is purely related to your own actions.
What we are doing, we are working with the operator of the other joint ventures, trying to push on each project to get the same level of reduction. You have to consider that more than 80%, 80-something percent is operated. That represents a really important part of our production. I said that we are working with the operators, and we rely on the operators. Most of our operators are the top company in the industry, so they are following, they are doing the same kind of process. They are following the same kind of process. In this case, we are considering just our equity cost and our operated production. No, they're all production, but with our equity cost.
That's it. Thank you.
Next question comes from Mr. Massimo Bonisoli from Equita. Mr. Bonisoli, please.
Good afternoon. Just a couple of questions. Regarding Libya, could you give us some color on the current production and safety situation in the country? Also, could you also comment on the market share decline in marketing volumes in Italy in Q4? Thank you.
For Libya, we are clearly constantly monitoring the situation because the environment is very volatile. Our priority is to protect our people, so the security of our people and the security of our installation. What we have done until now is, especially onshore, we create protection for all our activities. At the moment, we didn't have any damage to our facilities. 2013, we closed 2014 with an average production of about 140,000 barrel per day. The last quarter was very high because we reached practically our full capacity. We are close to 175. At the moment, we are producing like in the last quarter, close to 300,000 barrel per day. Also because in Libya, we renegotiate some gas, storage gas in the east that we sell because what tended for us, but useful for the east part.
We will have additional production also from this agreement.
As far as, probably you were referring to the oil falling demand that we recorded even in 2014 over in the range of 1%. There is nothing more unfortunately to comment in the sense that the fall kept on even in 2014, because of the, I would say, the overall depressed market. The only positive news on this perspective, I would say, the stop in the fall we justify at the end of 2014, beginning of 2015. The expectation is to see at least a stable number as far as 2015.
Okay, thank you. Just a follow-up. Can I just shoot another question? On the outlook for E&P, the outlook was positive for the production increase in 2015. Given the run rate very strong in Q4, do you feel more confident on achieving higher growth rate versus the guidance of the plan for 2015? Or should we assume more or less the same level? I don't want you to spoil the strategy presentation of course.
I don't want to spoil either. I just want to say that from a production point of view, I think that we will be able to increase our production about, as I said, 3% at the all plan level. If you consider the new plan level, we can reach because of the price effect of the PSC, also 5%, but the 3% are the constant price level, price scenario. I think that we can confirm the 3% of increase. In 2015, we have big projects that will start production. We talk about OCTP, we talk about Goliat, and we talk about West Hub. That is the situation. Clearly for 2015, we kept some important production contingency because of Libya. Also considering this contingency, our growth is 3% on average.
Very good. Thank you.
Next question comes from Mr. Marc Kofler from Jefferies. Mr. Kofler, please.
Good afternoon, everyone. Two questions, please. I just wanted to come back to the major project schedule for this year and potential FIDs. I noticed you've moved forward Sankofa offshore Ghana, and clearly there's quite positive commentary around Coral. Are there any more major projects which you'd expect to be sanctioning this year? Secondly, I was hoping if I could just double-check on the prior operating cost saving target, which you communicated. Was that EUR 500 million for this year? Thanks.
I think we can answer. We are anticipating too much because we are talking about FID for 2015. We can give you some preview on this. Roberto, please.
Yes. As I said earlier, Coral will be one of the major FID this year. I can also mention Congo and Angola.
Okay, thank you, Roberto. When you talk about OpEx and the reduction in OpEx, we talk about EUR 300 million, not EUR 500 million, EUR 300 million, the figures. On average, our operating cost for 2015 will be about $8 per barrel unit cost.
Right. Okay. The prior guidance going into today?
What?
Guidance?
Can you repeat, please? Because I can't hear you very well.
Sure. I was just wondering what the prior guidance ahead of today's presentation was for 2015.
No. That is the first time that we give the guidance for OpEx reduction. When you talk, maybe you mix up on the G&A, because last year we started with our G&A reduction cost, efficiency cost. We talk about EUR 250 million on G&A, and that was the guidance last year. For this year, the G&A guidance EUR 500 million, but the G&A, not OpEx. OpEx is EUR 300 million. I'm talking about euro only.
Okay, great. Thanks for clarifying.
Is that clear? Okay, thanks.
Next question comes from Miss Irene Himona from Societe Generale. Miss Himona, please.
Thank you. Good afternoon. I had a couple of questions, please. Firstly, on working capital. Obviously, as oil went from EUR 145, you released about EUR 3 billion. Now in Q1, we've gone from EUR 45 to EUR 62, but you still have the release of take-or-pay prepayments in gas. Net, what guidance can you give us for the present quarter, please, on working capital? Secondly, on refining and marketing, obviously the recovery in refining margin in Europe is seen generally as temporary. Can you split refining from marketing or give us some estimate of roughly how much of the improvement we show is self-help rather than margin? Thank you.
Okay, Irene, I'll give the answer to your question. As far as the working capital, again, we wouldn't like to release any kind of guidance even for the first quarter 2015. You exactly mentioned what we expect in this quarter from some items such as the take-or-pay. What we are doing is paying the utmost attention to all the other items in working capital, and this is happening also thanks to the reorganization that took place since May 2014 that allow the corporate people to have much more grip on this item all over the world. Again, the expectation is to keep on delivering on the exceptional items I mentioned and not to have any kind of worsening scenario on all the other items. As far as R&M, you asked about the breakdown of the refining versus marketing.
I'm referring to the full year economic results that you know are around minus EUR 200 million. This is the net effect of around EUR 600 negative from refinery and EUR 400 positive from marketing. The margin helped this result, especially in the fourth quarter that has been positive, even if you refer just to refining results in the range of EUR 30 million. Fairly speaking, on a year-on-year basis, the upgrade of the results, that is in the range of EUR 200 million, has been a 60% scenario and 40% result of all the efficiency measure, closure of additional capacity we just mentioned.
Thank you very much. Thank you, Massimo.
Next question comes from Mr. Rob West from Redburn. Mr. West, please.
Hi there. Thanks very much for taking my question. The first one is around the downstream and the refinery closures that we were talking about last year. It looks like more of those are going to come in as turnarounds or conversions to green facilities. Can you give some color on the differential cost of converting something to a green biorefinery versus shutting it down completely? Secondly, I noticed one of your partners in the U.S. has elected to defer paying the interest charges on some of its debt and the equity has basically gone to zero. How does that affect you within your U.S. partnership and any desire, if you could pick it up basically for free equity value to up your exposure in those shale plays? Thank you.
The conversion of the refinery, like the green refinery in Gela that has been announced in November, consists in the conversion of some assets into a biorefinery similar to the one that we have developed in Venice. The expectation of this particular technology, the refining technology, will allow us to process about 750,000 tons per year. The overall cost is estimated in about EUR 200 million-EUR 220 million, and the timing for completion of the project is about 24 months after the approval has been obtained.
We are not sure that we caught completely your question, but I think that you refer about Quicksilver.
Yeah, that's right.
Yeah. No, there is no intention to make any acquisition in the unconventional or increase our share there. We are working with them, but there's not any intention to make any acquisitions.
Okay. Thank you.
Next question comes from Mr. Jon Rigby from UBS. Mr. Rigby, please.
Thank you very much. two questions. one on gas and power, you'd be surprised to know. First, there's a comment, actually. I think some of your disclosure's increasingly obsolete as you develop a different business. I think I might have said that a couple of quarters ago as well. Is it possible, Marco, that you can break out or disaggregate a little bit further the impacts of the things you name-checked, I mean power, LNG, et cetera, on the delta on your performance? Maybe also is how much of that is maybe a seasonal effect or a temporary effect or whatever? Just give a bit more insight into if that is possible. The second question is on The exploration and the cut in exploration spend.
I guess it's an easy thing to cut, but you're fairly unique in the industry by actually appearing to drive quite a lot of value from your exploration business. I guess two questions. One, is there still a relatively high level of activity? You're not going to have to lose some of the momentum that you've clearly got in that business by shutting down spending. Second, do you think you're still able to monetize some of those discoveries? I think you said last year that one of the things that you would like to do is to accelerate the value in exploration by monetizing it, but I'm very conscious that the market right now might not let you do that. Thanks.
Michele, please.
Okay. Jon, keeping consistent with the disclosure that we do give, what I said before is the take-or-pay contracts, we bundle those together with logistics. Excluding retroactivity, you should assume that remains negative in 2014, also remains negative in 2015, when we expect to recover some one-offs with the GasTerra arbitration. The other segments, which is power, B2B, trading, LNG, and retail, are all positive throughout 2014 and expected to be positive in 2015. As we discussed previously, there's been a sharp decline in B2B compared to 2013, which was still living off what the market was like in 2012. I think the other value-added segments are stable and increasingly recovering, with the power business being exposed to the spark spreads. You can use your own curves and make those assessments going forward.
Okay.
Exploration. First of all, I want to assure that we are still explorationists, we like exploration and the evidence is that in 2014, we acquire about 100,000 square kilometers of new acreage. It is clear that we're going to continue to work on our best skill, and that is sure. We study our plan clearly in the details because we don't want to hurt ourselves. We didn't do that in the past, and after all this success, you can be sure that you are still more convinced about our potentiality. What happened that in the last seven years, without spending a lot, we found a lot of resources also in frontier exploration. Today, we really feel the need to look at value and resilience. That is really our big title for all our businesses, value and resilience.
That means that for our exploration unit, that is very efficient and effective, is to go close to our field or our near field or in filling or appraisal and puts all our skills to find oil and tying oil very quickly or gas, tying oil and gas very quickly. That is not a strategic move, but is a tactic move. I think that is, I'm kind of sure everybody, is that we don't want to hurt ourselves. We continue strongly with our exploration target and strategy.
The monetization angle?
Monetization, I forgot this point. I was so focused on exploration. No, I think the exploration asset are typically different kind of assets, not producing one for the long term. It's less impacted by the fluctuation of the market, of the price. Our assets are very good. Very, we can say cheap from a developer point of view or conventional. Here there is a good business also for the buyers. We can say that it's a good investment also for the buyer. They are not impacted, as I say, by the price. We are continuing and in discussion with different kind of people, entity groups, and we don't see any reduction in interest of talking about exploration assets. I think that they are recognizing a lot of value in it.
Okay, thank you.
Next question, and the last question comes from Mr. Neill Morton from Investec. Mr. Morton, please.
Thank you. Good afternoon, everyone. Two number questions, please. The first relates to the upstream business in Q4. Could you perhaps explain why there is such a big increase in the depreciation charge in the quarter on an adjusted basis? Following on from that, there's an implied very sharp fall in your cash costs in Q4. Secondly, I wondered if you could give us an up-to-date rule of thumb with regards to PSC sensitivity, for every $ move in the oil price, how your entitlement barrels are affected. Thank you.
Neill, the most important reason why the Q4 DD&A increase in E&P is because of the ramp up of the new production and the start up of new fields. That, as you well know, takes into consideration a higher depreciation cost because of the higher cost that has been spent recently in order to develop the field.
The PSA, yeah.
The PSA effect is in the, as far as 2015, in terms of volume, is in the range, is a little bit less than one. It's in the range of 0.8, 0.9 thousand BOE per day, every $ trend.
Thank you. Is that Q4 charge then a sort of ratable number for 2015?
Definitely the DD&A is expected to increase in time as the production ramp up, yes.
Because we have a lot of projects coming in, yeah.
For sure. Thank you very much.
Actually, they are also already operating.
Okay.
I think that the call is over. Thank you for all the attendance.
Thank you very much. Bye-bye.
Thank you. Bye.
Ladies and gentlemen, the conference is over. Thank you for calling Eni.