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Eni SpA
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Good afternoon, ladies and gentlemen, and welcome to the Eni 2018 First Quarter Results Conference Call hosted by Mr. Massimo Mondazzi, Chief Financial Officer. [Operator Instructions]
I am now handing you over to your host to begin today's conference call.
So good afternoon, and welcome to our first quarter 2018 presentation.
It was a positive quarter for the upstream and Gas & Power sectors, which benefited from the execution of our strategy and the positive market environment, whilst downstream results confirmed their resilience. In upstream, production was 1,867,000 boe per day, at 4.4% higher than last year adjusted for PSA effect, whilst reported production was 4% higher.
During the quarter, we started up the 5th field in Block 15/06, extending the plateau of this block. We continue to progress with the remaining start-ups planned for this year. First gas from OCTP is confirmed in June, while the Libyan project, Bahr Essalam Phase 2 and water compression will be delivered between June and September. We recently obtained the plan of development -- the approval of development from Merakes, which will be tied in to Jangkrik. And finally, in exploration, we delivered 2 main discovers, Calypso offshore Cyprus, [ Intercali 2 ] in [ Aragon ] in Mexico.
In the mid-downstream, we recorded EUR 400 million of EBIT due to a strong performance in Gas & Power with an EBIT of EUR 322 million, thanks to growth in LNG sales and improved midstream structural performance and positive results in refining and marketing in chemicals despite the weaker scenario.
Cash flow before working capital grew by 22% to EUR 3.2 billion, significantly exceeding the growth of the oil price that has been 8% on a euro per barrel basis. These result is mainly driven by the response of our highly profitable upstream portfolio to the improved scenario as well as the growing LNG volume sold.
CapEx were in line with the guidance, amounting to EUR 1.8 billion, net of the acquisition bonds for the Abu Dhabi field that amounted in the range of EUR 700 million.
And now a quick look to upstream. Production, as I already said, reached 1,867,000 boe per day, a growth 4.4% versus last year, boosted by the start-up and ramp-up contribution of 238,000 boe per day. The main contribution were from Jangkrik in Indonesia, Zohr and Nooros in Egypt, OCTP oil in Ghana, Ochigufu west [indiscernible] in Angola and Kashagan, whilst Goliat benefited from a better uptime. We confirm our full year production growth of 4% in a $60 per barrel environment.
In terms of EBIT, we recorded EUR 2.1 billion, a 47% jump versus last year as an effect of the [indiscernible] scenario and production growth, partially offset by higher depreciation cost mainly related to recent start-ups.
Excluding the impact of the Abu Dhabi one-off bonds, the upstream free cash flow was more than EUR 840 million in the quarter.
And now a brief outlook at the key main start-ups and ramp-ups that will drive our 2018 growth. In Block 15/06 in Angola, we started up the Ochigufu project [ ID ] to west [ top ] FPSO that achieved the first oil in less than 18 months from the presentation of the plan of development.
On Zohr, we recently started up the second onshore train, allowing the production to double to 800 million scuffs a day. We are planning to start the next few trains within the end of the year, reaching an equity production peak above 100,000 boe per day. OCTP oil contributed 19,000 boe per day in the first quarter and will double with the gas volume at plateau starting from next June.
And finally, Jangkrik, it has smoothly reached the plateau and delivers gas to Bontang LNG at a rate of more than 600 million scuffs a day. This field will be an important add for future development, as we will see in the next slide.
Overall, this year the contribution from start-ups and ramp-ups will be 310,000 boe per day.
Looking now at a key future project. The Merakes development received approval from the Indonesian authority 1 week ago. We completed the appraisal campaign at the beginning of 2017, and in less than 2 years, we'll be able to take the FID, planning to deliver the first gas in the second half of 2020. The estimated 2 tcf of gas in place will be developed by 6 subsea wells tied into the Jangkrik floating production unit, where the gas will be treated and connected through the existing pipeline to the liquefaction plant of Bongtang. This field, with a plateau contribution of 60,000 boe per day in share, is a material element of our integrated LNG strategy. Furthermore, the block contains additional structures that will be targeted by further near-field exploration.
And now to conclude the upstream section and leveraging on the proved reserves data now published by the entire peer group, let me present a discounted net cash flow view of reserves value.
In unitary terms, we share the top of the scale with $6.08 per barrel, pushing up the value of Eni's proved reserves to $48 billion, very close to peers with much larger volumes of reserves. This is the result of our high realization prices under the valuation scenario that you know has been in term of Brent at $54 per barrel and lower production costs, including the royalties, that lead by far the group.
With an increase of $2.6 per barrel versus the value of 2016, second only to one peer that in '17 performed a material reduction of its proved reserves portfolio to the benefit of its unitary value, Eni recorded a remarkable increase, justifying the value retention in an improving scenario.
And now, let's move to mid and downstream. In this quarter, we delivered strong results in Gas & Power and positive result in the oil and chemical mid-downstream. Gas & Power confirmed the progress made so far, achieving an EBIT of EUR 322 million, driven by the LNG and power operations and without the one-off of contribution that had announced in 2017 results.
LNG sales grew 35% at 2.7 bcm, thanks to the successful integration of gas upstream project in Indonesia, whilst retail gas recorded a result substantially in line with the first quarter 2017, excluding the sale of Belgium asset and the lower regulated margin in Italy. This performance strengthens the Gas & Power guidance we provided for the full year.
Refining and marketing is in line with the plan, taking into account a weaker scenario that impacted on the refinery result, counterbalanced by a positive market performance. The action we are developing in '18 related to the restart of EST and the Gela conversion to bio plan we'll further announce by the end of this year the resilience of our refining system, lowering its breakeven at $3 dollars per barrel.
Finally, Versalis maintained a positive quarter, with an EBIT of EUR 59 million, confirming its resilience in a weaker scenario.
And finally, some information about the cash flow from operation. With almost EUR 3.2 billion of cash flow from operation, pre-working capital, we increased our cash generation by 22%. It is the highest result since the third quarter of 2014.
E&P contributed EUR 2.6 billion, whilst the other businesses, largely Gas & Power, contributed the rest. Reported cash flow amounted to EUR 2.2 billion, a 13% increase versus last year, impacted by the seasonal working capital cash absorption, mainly in Gas & Power business, which is expected to be more than reabsorbed in the coming quarters. CapEx in the quarter were in line with budget at EUR 1.8 billion, and this allow us to confirm the EUR 7.7 billion guidance for the full year. Leverage remains at 23%, equivalent to a gearing of 19%. The full cash neutrality in '18 is confirmed at $55 per barrel.
Thank you very much, and now, together with any top management, I'm ready to answer any questions you may have.
[Operator Instructions] The first question is from Oswald Clint of Bernstein.
Just really 2 quick ones around the quarter, please. The first one, refining, obviously, good to see that's still positive here. Any trading losses or supply optimization negative impacts in the first quarter? And maybe remind us of the seasonality of the marketing for this business as we look into the second quarter and third quarter. Is there a big marketing earning step-up? And perhaps give us a bit of insight into how refining margins are behaving for you in second quarter so far. That's the first question. Second, [ in fact ] I was just looking at the volume growth in some of the regional breakdown. I'm curious about the declines. Pretty heavy declines you're seeing in Italian and European natural gas. Are those declines in line with your plan? Or perhaps you could talk around the kind of European natural gas production side please?
Okay. So thank you very much, Oswald. So in terms of trading losses, no, we didn't record any trading loss in the quarter. About seasonality in marketing, the best quarter as far as marketing is the second one. But anyway, we recorded strong performance in -- even in the third quarter, among the others taking, I would say, a solid market share in the range of 25% in a stable margin business. And in terms of refinery, no, we don't have any specific seasonality on this respect to. I will say what is the most important information is that we are progressing in line with the plan in taking our breakeven at $3 per barrel. So the progress as far as the EST rebuilding and the conversion of Gela refinery are progressing in line. So we really expect that by the end of this year we'll be in the position to match even a tight scenario as the one that we have been [ living in]. And in term of gas production, no, we are justifying exactly the depletion that we expected. So no huge -- no big differences on this.
Your next question is from Jon Rigby of UBS.
Just one question. On Gas & Power, you obviously referenced the good LNG results and also the adjustment from last year in the traditional supply business. But on LNG, are you able to sort of characterize either the absolute EBIT contribution from LNG or the delta on 1Q, just so that we can sort of assess how you're progressing? The level of disclosure in that segment has been great, and clearly, the first quarter results are significantly ahead of what we'd expected, I guess, given your full year guidance.
Yes, yes, Jon. So I'm going to give you some more detail, and maybe I'll leave the floor to Massimo Mantovani to add some information about the quality of the LNG business we are conducting. So we recorded EUR 322 million in Gas & Power EBIT first quarter. I will say retail is EUR 140 million, and mid-gas is EUR 180 million. On this EUR 180 million, LNG contributed more or less 1/2 of this value. That definitely is a significant increase versus what we recorded in the first quarter 2017 with, I would say, this one-off that we recorded at the time that has been in the range of $50 -- EUR 50 million. And then maybe I'll leave the floor to Massimo to give you some more detail.
Okay, good afternoon. And just to add, as Massimo anticipated before that, the increase of volumes was about 35% in terms of LNG. And that brings us overall around our plan to go a little bit more than the 6 million tons in the year. Of course, we took the opportunity of very good prices, in the Asian market in particular. And just to give you an idea, we are also targeting by the end of the year to have at least half of the volumes sold on the Asian market. And that is where we are going. In terms of increase of value we got from LNG, it was significant in the first quarter as compared also to the first quarter of last year. We are talking of around 40% more in terms of value which we took out. And so it's looking pretty good, and there is where we are going. We increased the equity production. And this year, we expect it to go around 2 million tons from Jangkrik. It's well positioned. So it's looking good.
So just to follow up. Given -- I mean our expectation is, I guess, with oil prices where they are and also decent demand for LNG, there's no obvious reason other than maybe some [ shoulder ] season effects in Q2 and Q3 that the contribution from LNG across the whole year shouldn't be pretty robust, right?
Of course, the price we are not expecting them to be as they were in the first quarter. But these are market analysis, but it's going to be a robust contribution this year.
But Jon, in the longer term, definitely we remain very positive on the LNG market. And that's the reason why we are pushing very much even on the additional Meraje project in Indonesia. So this is really a very strong project because of the big synergy that we could have with Jangkrik. So we are definitely fully focused on the development in this field as soon we can. So now, we are now seeing the first production by the second half of 2020. We're going to present the FID, I would say, in 1, 2 months, and we will keep on starting the future development in order, if possible, to accelerate the start-up.
The next question is from Ms. Irene Himona of Societe Generale.
I had 2 questions, please. Firstly, looking at the adjusted E&P, in Q1 your tax rate was 55%, and we had $67 Brent prices. Now a year ago, it was 58% at only $53 Brent. So there's some counterintuitive. I wonder if you can just give us a little bit of guidance as to what we can expect in the current $70 scenario on E&P tax. And my second question is on Q1 depreciation, EUR 1.83 billion. I mean, despite the strong production growth, year-on-year it is a flat number. I wonder if you can give us any sort of guidance for the evolution of that DD&A in '18, '19. And I wonder if over the plan, over the 4 years, can we expect that to grow towards an annual level of around about EUR 9 billion?
Thank you, Irene. So starting from your last question about the depreciation. So our depreciation now is in the range of $11 per barrel. That is the -- I would say that the level that we expect would be stable all along this year and remain pretty flat also in the next 4-year plan. You remember that when we commented during the start of the presentation our portfolio, we said that the CapEx embedded in our new development are in this range. So we do not expect looking forward, a significant change on this. Definitely, we are having a slight increase versus 2017 because of the slight change in our portfolio shape. For example, the new start-up, including a more constant production from Goliat, that contributing to come up with this $11 per barrel amount that anyway remain a very competitive DD&A in the industry. And the second, so you were commenting about the tax rates. So in the first 3 months -- in first quarter 2018, we got 55%. You are right. And we expect on a full year, I would say, at a scenario of $60 per barrel, we expect a number that will be pretty the same, between 55% and 60%. Overall, we expect the same tax rate, so 60% in a $60 scenario, Brent scenario. Definitely, there are some seasonality on this. So definitely, the first quarter has been a pretty positive quarter in terms of tax rate for 2 reasons. First of all, because we got, I would say, a full production from Goliat, having the same benefit that you very well now looking at these total results. So the tax rate and the tax you pay in this quarter are related to the previous quarter scenarios. So you have this kind of advantage in having this tax rate. And the second, the first quarter is a strong quarter in our Italian businesses that are benefiting from, I would say, a tax rate that is below the average. And if you look at the cash tax rate it's even 0, thanks to the losses carryforward we have in Italy.
The next question is from Mr. Alessandro Pozzi of Mediobanca.
I have 2 questions on Zohr. It looks like the field is ramping up nicely. Believe it should hit 0.5 million barrel of oil equivalents next year. I was wondering if you have already explored opportunities for exports on -- yes, if you can give us a bit of color on where you are basically on that. And also, second question is staying also on Zohr, can you remind us what is the share of the CapEx that will be reimbursed this year and the timing of the next installment from the previous transaction?
Okay. In terms of possibility to export, maybe I leave the floor to Massimo. And then to give you some update on the technical point of view, I leave the floor to Antonio.
In respect of export opportunities, and we do believe there is export opportunities from Zohr, Egypt. And in particular, we are looking at trying to restart the Damietta plant, which is -- of our joint venture with the Gas Natural with Unión Fenosa Gas that requires the settlement of quite long-standing mitigation with Egyptians, and discussion are on ongoing. And I think that is one opportunity. And then, the whole area is interesting in terms of gas production, and that may lead also in the future of opportunities different from LNG. But what we are focusing now is really to have as soon as possible Damietta back on actually exporting. And it's not an easy process, requires some negotiation that requires time. I think that was also somehow announced by Gas Natural that they are looking with us in trying to solve the problem.
When do you expect the settlement on the litigation?
Well, it's difficult because as is a litigation you normally -- it's difficult to set the time frame. But of course, the sooner the better. But normally, these kind of negotiations they do require time. It's not an issue of weeks.
Okay. Concerning the project development in Zohr, we are progressing very well as planned. As you know that we have already train 1 in ramp-up. At this moment in time, our rate is above [ 700,000 million ] standard cubic feet a day. And we're going to ramp up, as we mentioned in our press release, to 800. Then immediately, I think a week from now we expect to start producing also through train 2. And then the sequence, as we mentioned, train 3 and 4, reaching 2 -- over 2 billion by the end of the year.
So I didn't catch very well your last part of the question that relates the recovery of the purchase price for the dilution in Zohr?
Yes, the share of the reimbursement for the CapEx.
The biggest part would be cashed in, in 2018, including the remaining 10% that we recently sold to Mubadala. That is, I would say, nowaday close to completion.
Okay. The total amount?
For amount, it would be will be in the range of EUR 600 million.
The next question is from Lucas Herrmann of Deutsche Bank.
Massimo, just some points of clarification or understanding, if I might. On Zohr, it's a profit share. Do you pay tax or do you treat any level of payment to the government as tax? Or is it just by a barrel? And secondly, I just wonder whether you can -- could remind us, in terms of the volumes produced from Jangkrik how much goes to Pertamina? And how much do take into your own portfolio for sale to customers on a spot or other basis?
So I didn't catch very well. Your first question, that relate to the payment to the government on what?
Sorry, Massimo, the first question, what's the tax on Zohr? It's a PSC. Effectively, you contribute production to them. Is there a tax rate applicable to the cash flows that you receive? Or when you consolidate the numbers from Zohr or the results of Zohr, is it effectively without tax? A phenomenal comment. It goes back to Irene's observation around the movement in taxation this quarter and, again, you're thinking forward as the portfolio shifts away from Libya and towards -- and more towards Egypt and Asia.
To Zohr is 30%. It's a corporate tax rate.
Pertamina?
And as far as the share of, Massimo could give you some detail.
As Eni, we do buy around 40% of the production. And you were mentioning the spot market. We do have sales which are somehow linked to Jangkrik, but of course, we do have a lot of trading around the floor. So we do have long- or medium-term sales like to Pakistan and China. But that goes into portfolio with all the other supply we have in terms of optimization of shipping and deliveries.
Massimo, just to understand that better. Eni upstream sales to Eni G&P at a contracted or at some arranged price. And any excess that is taken -- or any excess, I'm going to say, that is taken or margin that's taken between G&P selling to Pakistan is -- or elsewhere is accredited or is that taken in the G&P business, is that correct?
Let me specify, we do buy from, let's say, upstream or the joint venture at market price for that kind of contract, which is a long-term contract. Then of course, we do sell on a different basis, including also spot market. And the margin which we get from that, of course, stays with us. It's our LNG portfolio [indiscernible].
Okay. I'm really sorry to push. One final quick question. When you say market price, it's a long-term contract price that you negotiated which is whatever it is, I guess. Or can you add any more color on what the contractual terms are between upstream and G&P on LNG deliveries?
Long-term oil link contract.
The next question is from Theepan Jothilingam from Exane BNP Paribas.
A few questions, please. Firstly, just on the financials. You talked about the working cap being reabsorbed. I was just wondering whether you may be able to give us a better guidance how through the year we should model that reverse of the working cap, if that's possible. Is it back-end loaded? Or is it evenly across the next 3 quarters? Secondly, could you just reconfirm plans on FID in Mexico and whether you can give any color potentially in a [ fund down ]? And my third and final question is just on Cyprus and block 6, perhaps you could just clarify what activity we should expect going forward in the next 6 months.
Okay, Theepan. I'll give an answer to the first question, and then I leave the floor to Antonio as far as Mexico and Luca as far as Cyprus. So in terms of working capital, I said that we expect the absorption of the -- working capital absorption that we recorded in the first quarter. The absorption will start definitely by -- the second quarter has the most important phenomenon underlying is the Gas & Power seasonality. So Gas & Power seasonality definitely will turn starting from the second quarter, as did always in the past. The absorption will be progressive, as we expected by the end of the year a positive contribution from working capital. So the guidance on this respect remain the same guidance we gave presenting the 4-year plan, in particularly the budget, where we announced a positive contributions, slight positive contribution from working capital. And then I leave the floor to Antonio to talk about the Mexican FID.
Okay. The Mexico situation that we have we been working with the authority to conclude the final POD, which has been submitted as a final form in December. And we are waiting now and expecting receival of approval in May. Immediately after, we're going to do the FID probably on the third quarter of 2018.
And Luca about Cyprus?
About Cyprus, we plan in second half of the year to carry out all the necessary environmental impact assessment for an appraisal program of Calypso, starting sometime in the first quarter next year.
Any color in terms of a [ fund down ] in Mexico?
Yes, definitely -- [ definitely ] Area 1 is a good candidate for future [ fund down ]. I would say some discussion are going -- ongoing, and we will let you know as something is, I would say, more mature on this.
The next question is from Marc Kofler of Jefferies.
I just want to have 2, please. Firstly, I was hoping you could give us a bit more color about current production. And I suppose linked to that, can you say a little bit about how the -- your volumes from offshore UAE, from Abu Dhabi, currently stand? And then also perhaps how you feel the broader relationship with the UAE is progressing and any kind of future opportunities there?
So some color on current production. What I could say that definitely the second quarter in terms of maintenance will be the harder one. So we expect the most important maintenance stop in second quarter. While in third and even less in fourth quarter, we expect a strong ramp up. As far as the relationship with the UAE, so we acquired the stake, and our relationship with them is, I would say, quite strong. And they are thinking about a new collaboration. And really, we are really keen to pursue such an opportunity. Again, it's premature now to talk about this, but definitely the relationship are very well.
Great. Can I just follow-up on that? Would those relationships, are they exclusively in the upstream?
[indiscernible]? No. Maybe the discussion could be open even on business other than upstream. I mean, mid-downstream.
Our next question is from Mr. Massimo Bonisoli of Equita.
One quick question for me. In Q1, the realized gas price in E&P division was $4.5 per million btu, quite a sharp improvement versus Q4 and Q1 last year. Could you give us some color on realized gas price over second quarter considering the European gas prices and LNG are still pretty strong?
The gas price we recorded in the first quarter is a sign of, I would say, strong realization price in our portfolio, even in gas. Definitely, the number has been some way pushed by the seasonality of the market. If you refer to the, I would say, the production -- the gas production, we sell in Europe. So the Libyan gas, the Norwegian gas, the Italian gas, by definition, some way we sell the price -- the gas to their price. Some way this gas benefited from the peak because of the seasonality, a peak that definitely will drop in the second and third quarter. So this is the natural, I would say, wave as far as our production link to the [indiscernible], while in the fourth quarter, we will see how cold is this season and the level of the price we can get at that time. As far as the rest, definitely, the number you mentioned are a sign of how flexible and reactive are our additional gas sales all around the world on top of the European one. And on this respect, we expect that this price will remain high even in the next quarter.
And the next question is from the Biraj Borkhataria of RBC.
I have a couple of questions. The first one, you talked a bit about tax. Could you just update us on the cash tax guidance for 2018? I know you typically talk about the $60 reference in our EBIT. Could you also provide a provide a bit of color on how that could evolve in today's environment? And then the second question is could you provide an update on the key exploration wells for 2018 and what we should be watching out for?
Okay. So the tax -- the cash tax guidance as far as '18 in this scenario will be in the range of 25%. And now, I leave the floor to Luca to elaborate on exploration.
On exploration, we have the majority of our activity in the second half of the year. And the countries where we'll be more active will be in Angola, Ghana, Indonesia and Egypt.
Just to follow-up on the cash tax guidance. Is the 25% you referred a $60 reference scenario? And should we expect that to be roughly similar in a $70 or $75 scenario?
We expect a slight decrease in case of $70 scenario.
The next question is from Mr. Thomas Adolff of Crédit Suisse.
Three questions, please. Firstly, on Indonesia, you talked about additional structures. So I was wondering are we talking about similar sizes to Merakes. And maybe you can comment around the risk perspective upside you see across your licenses and trying to better understand whether Eni Indonesia after Merakes comes on stream will have a longer plateau than we think or potentially even a higher plateau. Secondly, going back to Egypt and Damietta. You talked about Damietta. Obviously, you have a stake in there, but there are other idle facilities in country. So I wondered whether -- I'm presuming the other facilities don't have this dispute going on, that you could actually use the other facilities to export some of your gas. And thirdly, just a very random question. I wondered whether you can provide the spread between 1P and 2P in terms of reserve life. What's the 1P versus 2P reserve life? What was it in 2017 and what is it in 2016?
So regarding Indonesia, I confirm that [ matter of ] Merakes we have other prospectivity in the area nearby in the range of 50 kilometer from the FPO of Jangkrik. And this prospectivity will be drilled in the coming 2 years. The size of this prospectively is in the range of the Merakes size, so from 1 to 2 TTCF of gas for each prospect. And of course, in first phase this will be used to maintain the production and to elongate the plateau of FPO of Jangkrik. In case of additional significant discoveries, we may also increase our deliverability up to 1 million bcf per day in the future.
In respect of Damietta, let me say 2 things. One is that for what concerns to us considering that we are partners in Union Fenosa Gas, and there is not only the use of Damietta as a plant, but there is also the gas supply agreement which needs to be feed by the Egyptians. That is where we are aiming. And the solution for export from us will pass through there. In addition, as a second point, I want to underline that I believe that in general the Egyptians have to solve the Damietta issue before they can actually export. There is also an issue for reliability of what is happening on Damietta. And I think that it is in the interest of all parties. So there are arbitrations, but I think there is willingness from all parties to try to find a solution in the next weeks or a few months.
As far as the 2P reserves index, I'll give you the number. Just a second. So we are talking about something in the range of 17 years.
The next question is from Rob West of Redburn.
Can you make some comments on your underlying upstream costs during the quarter? We don't see those. And I guess there are some questions in the market about reinflation or if there are any one-offs in the upstream costs from 1Q. Second question, later in the quarter there was some press around plans to increase investment in Algeria in the next few years. Did something change there? Was that in the plan you presented to us back in March? That's the second question. And if I could sneak a third one in quickly. Just going back to Raj's question and Irene's question before me, do I infer from your comments that you're expecting cash tax to run below P&L tax for the majority of the year?
So as far as your third question, if I well understood, so below...
Will the dollar payment or the euro payments of cash tax be lower than the P&L tax you book on the income statement?
Yes. The answer to your question is yes. And as far as the cost, and before leaving the floor to Antonio, Alessandro to have say a market view on this, I would like to confirm that we expect in 2018 an oil price per barrel that would be in the range of $6.5, $6.7 per barrel, so remaining pretty flat. While I've already commented about the DD&A in the range of $11. So we confirm our technical cost well below $20 per barrel. Then I leave the floor maybe to Antonio, Alessandro to elaborate a little bit on what they see on the market in term of [ new ] Cost.
In terms of cost environment that we were seen during the first Q of this year, the sector of the offshore drilling rig we see substantially a steady situation with respect to the previous year. While for umbilicals, line pipe and subsea production system, we see this categories that are mainly driven by raw material costs we start to see a slight increase on the supply of this [ attainment]. The same can be said regarding risers and flow lines that after a period of very low market and now this seems to be stabilized. Also, for turbo machinery cost, we see a slight increase. With respect to our development cost, being more of our -- most of our development activities being already awarded, we don't see any impact by this kind of cost rising in the market. I leave the floor to Antonio.
Okay. Concerning the cooperation agreement and that we have signed with the Algerians, this is a cooperation agreement starting from subject relating the exploration activity and technology with the Sonatrach. In addition, we have a larger implementation of studies for solar panel activity in our fields. In addition also, we are evaluating blocks surrounding to our existing production facilities, focusing gas reservoir. This is the main relationship we signed recently. And anything is going to come require the FID or development. Definitely, on this 4-year plan, we have adjust part of that cooperation agreement activity. Thank you.
The next question is from Mr. Christopher Kuplent of Bank of America.
Just 2 questions left. I wonder whether you can help us a little bit outlining the impact on your financials from the -- I'm going to call it asset swap, i.e, selling 10% more of Zohr and gaining access to those Abu Dhabi concessions. So perhaps you can give us a hint, not just in terms of [indiscernible] but also in terms of the free cash flow generation that you're swapping. Should we assume that that's neutral? And secondly, a wider question. Just want to understand across your many different projects how much spare capacity is left in your system in places like Venezuela, Libya, Kashagan and Goliat? How far are you away currently -- not in Q1, but currently from what you would consider a business plan run rate in these projects?
Okay. So in term of what you have called a swap between Zohr and Abu Dhabi, definitely, the value that has been paid by both party testify that we are talking about something that in term of MPV is very similar. And then you can say that this proportion is in place every year, but definitely, the start-up and the production contribution is different year by year. So Zohr is ramping up right now, while, I would say, one of the license we acquired in Abu Dhabi will ramp up later on. But the contribution today in term of production is higher from Abu Dhabi than Zohr. So it's difficult to have this kind of comparison. As far as the spare capacity we still have. But we are ramping up in the places that you mentioned. So the ramp-up is expected to complete by this year. So talking about Jangkrik, talking about -- definitely, Goliat is not a ramp-up, but I would say a stable uptime. Even in Kashagan, we expect, I would say, that the ramp-up of the larger part of the ramp-up would be achieved by this year. And then what you called spare capacity will come through maybe some additional project, as we are doing in Libya. So the project we mentioned, so Bahr Essalam Phase 2, an additional phase in Wafa, are additional phases that will add some production to production that already exists.
The next question is from Christyan Malek of JPMorgan.
I -- 3 questions. First, on Egypt, the new gas law that's been put in place. Do you anticipate without some fiscal regime change any improvement in gas price terms? And with that, any potential sort of renewal around contracts on incremental investments that you put through? The second question is regarding your breakeven threshold for new FIDs. As you sort of manage efficiencies and you've sort of your supercomputers and so on, what is that level or sort of threshold in which you will sanction your projects, particularly in deepwater? And the third question is -- and then might be too early, just after your CMD. But on your cash return, given how competitive your cash breakeven has been quarter, would you consider expediting your buyback or whatever form of cash return this year?
I leave the floor to Antonio to talk about Egypt, and I'll give you an answer about the second and third question.
I think the -- I like to confirm you the existing contract in place are not related to this new law that you are mentioning today. So our contract are fixed, and tax is already in the agreement. We don't expect any changes from the actual situation.
Okay. In term of breakeven number project, you mentioned mainly the deepwater. So you know that our current portfolio for new development project is in the range of $30, even lower than $30. That's a mix in a portfolio that is made by onshore, offshore, deepwater, shallow water. Even talking about deepwater, there are so different project. For example, Zohr, that definitely has a breakeven that is much lower than $30 is a deepwater. So it's very difficult to give you an answer. What I would could say that nowaday when we decide to take in FID and to commit ourself for a new project, definitely, our aim is to take our overall cash breakeven at $30 or even lower than $30. In term of cash neutrality, definitely, the level of cash production is running, I would say, well in line with the expectation that we presented when we present our strategy in March and April. We expect following this pace that the leverage would be at 0.2 or even lower than 0.2. But I would say, it's too early to think about an additional cash return. As I said, the threshold would be to have a leverage below 0.2 in a stable environment. So a stable environment, definitely, could be evaluated at least in the second part of this year or I would say even better starting from 2019.
The next question is from Mr. Martijn Rats of Morgan Stanley.
I wanted to ask you 2 things. First of all, given your position in Libya and Venezuela, I know you've already commented somewhat about the projects you're doing there. But I was wondering if you could give us sort of the broader thoughts about the operating environment of those countries and whether you see that improving or deteriorating and what that could mean for overall production from both of these countries. That will be much appreciated given your sort of expertise in those particular countries. And the second one I wanted to ask may be a little nitty-gritty. But if you look at U.S. exports of crude oil going to Italy, they've ramped up quite a lot over the last couple of months. And now, I'm actually quite not sure whether they -- that crude makes its way into Eni refinery, specifically. But I can imagine, given your refining position in the country is very large, it probably does. And I was wondering how you think about the attractiveness of U.S. crudes. And is it specifically shale crude that you're taking into refineries domestically? And how much more of that could you still take?
Okay, so Antonio give you some color about Libya, and then I will respond the rest.
Libya as of today, we are continuing our operation. And we have a shutdown in, as you know, in Malita for integrity on our facility to tie-in our Bahr Essalam Phase 2 wells, which immediately, I think in a couple of days, we're going to ramp up again. And the situation in all our sites are really nice. And we are producing quite well with -- and good relationship with NOC. I don't see -- I cannot say that we have issues in place at the moment.
As far as Venezuela, normal activity are running as far as Perla. So we don't have any kind of constraint or trouble in this. As far as the recovery of our standing that you know, it was in the range of EUR 600 million by February when we announced the strategy. Now it's some tens of million higher than this, in the range of EUR 650 million. I would like to remember that the overall revenues, 100% our share of revenues, in a year is in the range of EUR 300 million. So the maximum ramp-up in our exposure is in this range. And now, we are at EUR 650 million. We are engaging negotiation with them, trying to stop the payment that now, I would say, pretty low or close to 0. I would like to remember also that our expectation are, I would say, realistic on this respect. So from one side, we stop any further investment in countries. So now, we are operating what we have without any additional cash injection or whatever expansion for further phases and on the other side that we are trying to recover the outstanding. But our projection as far as 2018 and '19 are very conservative. So when we are releasing numbers such as cash projections, cash neutrality, we are assuming, I would say, that payment from Venezuela that are, I would say, just in the range of more or less 20% of what should be due, more or less equivalent to the cash cost we have to sustain in bolivares. No more than that. Sorry, the last question about crude oil coming from United States, the answer is no. So we are not -- we do not project any kind of crude oil acquisition for our refineries today from the United States.
Okay. It seems like there are no more questions. So thank you very much, all, and see you soon. Bye-bye.
Ladies and gentlemen, thank you for participating in the Eni conference call. You may disconnect your telephones.