Eni S.p.A. (E) Q2 2018 Earnings Report, Transcript and Summary

Good afternoon, ladies and gentlemen, and welcome to the Eni's Second Quarter Results Conference Call, hosted by Mr. Claudio Descalzi, Chief Executive Officer. [Operator Instructions]. I will now hand you over to your host to begin today's conference. Thank you.

Good morning, and welcome to Eni's first half results. The first half results confirmed the strength of our industrial performance. Upstream production was more than 5% higher versus 2017, considering the DSA effect. Growth was sustained by the contribution of major ramp ups, such as Zohr and Kashagan and the startup of Ochigufu in Angola and Bahr Essalam Phase II in Libya. Exploration continue to deliver great results. During the first half, we drilled seven successful wells for a total resources of 280 million barrels at an exploration cost of $1.4 per barrel. Finally, we announced a strategic step in Norway with the creation of Vår Energi. Moving to Gas & Power, the structural change we have implemented in the first -- in the past four years allow us to achieve a strong performance increasing EBIT to €430 million, more than doubling 2017 results. Downstream businesses, impacted by a weak scenario, confirmed their resilience with an overall EBIT of almost €150 million. Moving to the financials. Operating and free cash flow growth are the most remarkable achievements. In summary, the first half, we generated €6 billion of operating cash flow, a 22% growth versus 2017. CapEx was reduced by 14% to €3.7 billion. So we generate an underlying free cash flow before disposal of €2.3 billion, largely exceeding the €1.35 billion of interim dividend paid in this period. Thanks to this strong cash performance, we reduced our net debt to below €10 billion, the lowest level reached since 2006. This corresponds to a leverage of 20% at the end of June, and the gearing of 16.4%. Before detailing the result of each business, I would like to give more color on Norway. We agreed with the private equity, HitecVision, to manage Point Resources into Eni Norway, creating a new company, called Vår Energi. We are expecting the completion of the deal by the end of 2018. The new entity will be a leading Norwegian energy player, with a widely diversified portfolio, spreading from the Barents Sea to the North Sea, and producing around 180,000 barrels per day this year. Vår Energi has 17 producing oil and gas fields, and more than 500 million barrels proven reserves. Building on the existing organization and leveraging complementary strength, we will grow production through a pipeline of 10 already existing projects to 250,000 barrels per day by 2023. In total, the company will focus over the next five years on bringing projects on stream and utilizing older fields and exploring for new resources. This is fundamental step in our strategy to reinforce Eni's presence in OECD countries with strong upstream potential, such as Norway, delivering an immediate impact on financial indicators with a reduction of around $2 per barrel in our cash neutrality by 2019. Also, this year, we have achieved major exploration successes both in near-field discoveries and in new basins. In Block 15/06 in Angola, we discovered Kalimba, bearing around 300 million barrels in place of high quality light oil with an estimated production rate per well exceeding 5,000 barrels per day. This discovery will open new opportunities for all exploration in the southern part of the block, which has, thus, far been considered mainly a gas area. We plan to apply the discovery and then to tell you the FID within the end of this year. Our expectation is to put on stream the field by the beginning of 2022. This will be a fast-track project, maximizing synergies with the East Hub, which is only about 55 kilometers away. In Egypt, we made two oil discoveries in South West Meleiha in the Western Dessert. These discoveries tested the deep geological sequences of the Faghur basin, a new oil discovery -- a new exploration play. During the production test, the wells delivered more than 5,000 barrels per day. These Egyptian discoveries, together with other prospects that will be drilled in these basins this year, will rely on fast drilling phases, low cost and synergies with existing facilities. This will accelerate our growth in this new production area, where we are already producing about 53,000 barrels per day. Finally, we achieved important results also in new areas in Area 1 in Mexico with Tecoalli 2 and in Cyprus with the offshore discovery of Calypso, a leading gas discovery, which proves the extension of the Zohr light play within the Cyprus exclusive economic zone, where the joint venture is now working to prepare the price of land. And now a quick look at production results. Production in the first half reached 1,865,000 per day, 5% higher than last year. We had positive performance from ramp ups and start-ups, mainly in Egypt, Indonesia, Angola, Ghana, Congo and Kazakhstan, contributing 263,000 barrels per day. And on the other side, we had some production reduction due to a major maintenance program in Algeria and in Libya, where the down time was higher due to the tie-in of Bahr Essalam's Phase II wells and the natural depletion in some fields in the U.S. and U.K. We confirm the production growth of 4% in 2018 at budget scenario. We achieved an EBIT of €4.83 billion, more than doubling last year's results due to scenario effect for €2.1 billion, better production performance for around €500 million. Let's now have a look at Zohr, where ramping up is proceeding faster than plan. After the start-up of first train in December 2017, we added four new treatment units. Each production unit has an average production capacity of 400 million scrap per day. We will increase production from the current 1.2 Bcf per day to 2 Bcf per day by September this year. The final plateau will be reached in 2019, with the start-up of the last three production units. The valuable contribution of our production was related into a strong operating cash flow growth. Upstream cash generation was €5.5 billion, 38% higher than last year, thanks to volume growth and the scenario effect. With upstream CapEx of €3.2 billion in the semester, E&P generated an underlying free cash flow for €2.3 billion, including disposals, more than covering our interim dividend needs. The cash flow per barrel grew to $20, in line with our plan and well above the level of $13.50 per barrel of last year -- no, no, sorry, yes, €2.3 billion, excluding disposal -- not including, yes, excluding. Gas & Power EBIT has doubled versus last year with a steady retail contribution of around €130 million. The strongest improvement is related to midstream, where EBIT increased by nearly €250 million. Looking detail into midstream growth, €70 million was related to higher LNG volumes, 60% more than 2017 and stronger margins capturing the good condition of the Asian market, where we sold roughly half of the volumes. €70 million was linked to the better power results and the remaining amount to logistics, efficiency and contract renegotiations. Take into account the results achieved until now and the seasonality of Gas & Power performance during the second half, we improved our yearly EBIT guidance from €300 million to around €400 million. Downstream was impacted by the challenging scenario in the first half of this year. In R&M, we achieved a positive EBIT result of €80 million, notwithstanding the lower scenario that impacted the refining activities. We will continue to strengthen our R&M businesses to make it more competitive, targeting a reduction of our break even margin toward $3 per barrel level. In particular, we will further optimize logistics and operational cost through integration and efficiencies, complete our buy through a plant in Gela by the end of this year and restart the [indiscernible] and consolidate our marketing position in Italy. In the Chemicals sector, the scenario is being characterized by some negative factors. High cost of [indiscernible] occurred in second quarter, not yet entirely reflected in the product prices, and in excess of supply in the European quality land market due to higher export from U.S. Notwithstanding these very difficult conditions, our result was positive with an EBIT of €65 million in the first half, showing the resilience of Versalis. In the second half of the year, we expect a further improvement mainly due to the continuous focus on operational performance and higher product prices. Considering this rebalance of market, and thanks to the positive contribution of the industrial and marketing action, we now forecast for the downstream and the overall EBIT of more than €500 million, of which €330 million is from R&M and €180 million from Versalis. Looking at our consolidated results. Thanks to the strong cash generation achieved in the first half and take into account the disposal, cash in and the dividend payment, the net debt for the first time since 2006 is below €10 billion, and our leverage is 20% -- is at 20%. In terms of full year guidance, we will generate a cash flow from operation of more than €13 billion, which includes a minor contribution from working capital and the cash in related to 2017 Zohr disposals, with CapEx of around €7.6 billion, and the running free cash flow before disposal is expected to be €6 billion, a 40% growth versus our original plan. This confirms our capability to more than capture the upside related to the improvement in this scenario, and we confirm the cash neutrality of $55 per barrel. And now with Massimo and the top management, we are ready to answer your questions. Thank you.

[Operator Instructions]. The first question is from Oswald Clint of Bernstein.

I want two questions, please. The first one is on your last few commentary on leverage just almost reaching the 20% level at the end of June. I think that the strategy that you spoke about, balancing strength in excess of that or below the 20%, you would talk about buybacks and the potential for those. So maybe just update us on that number, where it might progress, and ultimately, what that means for that possibility of buybacks, please? And secondly, I was just curious about your recent dealings in Algeria with Sonatrach. The press release earlier in the year spoke about significant cost savings and operational efficiencies, but also seems to be some upside potentially with the gas supply agreement, so maybe upstream and in Gas & Power benefits here from that deal, I just wonder if you could talk about that set of negotiations, please?

So for the first one, so the buyback, once we reach or we are below the 20% leverage, I can just confirm what we said during our strategy presentation. So we said that we -- once we are below the 20%, and considering the scenario, we are steady below in the 20%. We can consider. And I propose to our board a buyback and that is inside our policy, so our remuneration policy, and that is confirmed. For Algeria, yes, we signed two different agreements. And the agreement is a general agreement that aim to reduce cost because we have several activities in Algeria, so we agree with Sonatrach to put all these activities, and match out this activity under just one umbrella and create strong synergy and reduce cost, the operating cost. And that is being done, is in progress and with good results. Then we find agreement on the gas because we have gas in Algeria that produce as associate gas, and we have gas in -- underneath level where we produce oil. So we signed an agreement to export this gas that we produced in the south to our facility where we treat gas in [indiscernible] from the BRN fields, where we produced this gas, and that is -- will be an additional improvement in terms of efficiency, in terms of reserves, in terms of quantity of gas that we can deliver. And another former decisions in Algeria that we are replacing in our activities and also in the future in Sonatech the gas that we use for internal consumption with renewables in this case with solar or photovoltaic, and that is -- make an additional gas free for export or for domestic consumption.

The next question is from Thomas Adolff of Crédit Suisse.

Two questions for me please as well. Firstly, congrats on the deal in Norway. Hopefully, life gets a bit easier and better now. You've mentioned that near-term cash flow breakeven will improve by $2 in 2019. And I wondered whether you can provide a bit more color how this breakeven or the contribution will look like in maybe 2021? I understand that your portfolio, ex-Point Resources, contributes a bit more growth a bit later than Point Resources. Second question is more to do with the IMO, but a bit less to do with what upside you may see on refining. But I'm just more interested in the type of crude that you have that you produce in the upstream, so the overall crude gravity and sulfur level. So in an IMO world, would Eni's price realization improve or worsen versus what you see today?

So the first question will be answered by Massimo and the other from...

So Thomas, the effect is due to the different timing in terms of the short-term operation versus CapEx, And so that's the reason why we recorded an improvement in our cash neutrality by 2019 of around $2. And then we expect, thanks to the investment production growing to 50, that would be the final result. All these based on existing projects already clear, are very well identified in our portfolio.

Thank you, Thomas, for your question. As we already mentioned in several other occasions, Eni will be able to satisfy the requirements of the IMO to resume production, capable of achieving a zero production of fuel oil. And this is due to the fact that we are highly conversion system. We explore the EST, that as you know, is on the phase of rebuilding in Sannazzaro, their RHU that is a residue at the treatment unit in Taranto and [indiscernible] refining plus system integration. On this aspect, let me also emphasize that we just restarted the Taranto refinery that was offset -- applying to allow the work to make the plant able to refine also the temperatures of crude that is 10- to 22-degree gravity. In general, we don't expect our slate to lighten in the coming years, and on average, we have a slate that is about 30 degrees RP in density.

Yes, I was just more interested in your actual upstream production, not the -- what crude you process in the refineries. Because the other side of the equation is, clearly, if I'm producing medium gravity, very low sulfur volumes in upstream, let's say, Lula in Brazil, I'm going to see an improvement in price realization. So I wondered what dynamics we should see in Eni's upstream price realization.

One second. We are checking the few data. But I can start giving a quality answer, and then we talk about the figures. So our average crude production in the upstream is light, so it's light oil with a very low sulfur content. So I think that from generally speaking, not just talking about our refineries, but all the different refinery that we use, we are going to have an improvement from this point of view considering our kind of crude. Honestly, I cannot give you now, but we can give you -- we can let you have the differential and of a match that can be listed.

Well, this is great. I just wanted to know that you will benefit from it.

Yes. Yes, sure.

The next question is from Irene Himona of Societe Generale.

I had two questions, please. First of all, on Gas & Power. Obviously, very strong results, and you're increasing your guidance for this year. Back in March, in the start of your presentation, you presented the retail gas business as, let's say, the growth engine in that division's four-year plan. I wonder if you can talk a little bit about the performance of retail in the first half and second quarter results. My second question, again, you mentioned, Claudia, the continued strong exploration results in the first half of the year. Oil prices, obviously, are above plan, above expectations. My question is, at what point would Eni or should Eni, given your track record as a top-class exploration company, at what point should you treat $75 oil as a market signal that, actually, the industry has under-invested, the market needs more supplies, and therefore, given how good you are at it, that you should actually contemplate increasing your capital expenditure above the €32 billion you budget for the next four years?

So Alberto can give you some color about retail gas or Eni gas e luce, and the train, then the result in the future.

Yes. Thank you. In terms of results of the first half of Eni gas e luce, the results were quite strong. We reached €130 million of EBIT overall. And in terms of clients, we increased our customer base from 8.5 million to 8.8 million. This is making us confident that we should be reaching our target in terms of forecast of 9.1 million customers and around €200 million of EBIT, so that...

So considering the second question that is related to when we can -- things to increase our CapEx because we have so many resources, and within that, the price now is stable or we can go, and we need the additional production. So if you look what we have done in the last four years, we never reduced our growth on our investment. We try to have a different kind of attitude and approach to be able to increase our production, reducing our CapEx, and without leaving behind us any kind of project of opportunities. So we develop everything. And Zohr has been developed with a very -- so in a price scenario that we were, in average of $40 per barrel, we took [indiscernible] €12 billion. But at the end, what happened that through our exploration, dual exploration, we are able to reduce our capital. We reduced our exposure, we can continue to develop. So for one side, we have an organic growth starting from exploration low cost. So in upstream, that's a very low cost, where we don't need a lot of investment. We don't have complex, super complex and mad projects that oblige us to put a lot of money. We learned. We know everything about that. So in the last way, yes we changed. Low CapEx because our costs, our breakeven is low. Secondly, we use another tool, the dual exploration, to reduce our exposure without really -- without leaving underground the opportunity in the oil and the gas. So I don't think that also, with the higher, we can say, higher price, with the kind of asset we have, we are obliged to invest more. I told you that this 55 cash neutrality, 50 cash neutrality, so this area of cash neutrality for us is a must. It's a must because it's the only way to be able to face any kind of environment. But it's a must also because we use a model, using a philosophy approach that allow us to invest because our costs are low, and we have the dual exploration to spread -- reduce our investment risk. So the answer is we're going to continue to grow. We have 3.5%. This year, it's 4%. We'll be 3.5%, maybe more in the future. But we want to be really strict and disciplined, and use the strong discipline in terms of cost and capital allocation.

The next question is from Alessandro Pozzi of Mediobanca.

The first one is on Mexico. I was wondering if you can give us an update on the development plans there. The second question I have is on the exploration opportunities. I was wondering if you can perhaps highlight key exploration wells for the second half of the year. And finally, gas realizations on Zohr, I believe the Egyptian government is looking to raise domestic prices, gas prices. Just wondering if that has an impact on Zohr as well?

Sorry, for Mexico, Antonio can say something about the future development in exploration. Luca and then can say something about Zohr and gas prices.

Okay. So as you know that the -- we've been working with the authority in the last couple of months to finalize the POD. So everything has been completed. And in a weeks' time, we expect to get the approval. And then immediately, on the third quarter, we will have FID. This is all on Mexico.

On exploration, second half, we will add wells in -- one well in Indonesia, targeting additional resources nearby our Jangkrik hub. We will also continue drilling in Egypt in the Faghur basin additional wells to explore the potential of this new play, and also we will start the drilling of an offshore well in Egypt, a deep well that is named Noor. Finally, we will have a couple of wells in Norway, and we will restart our exploration campaign in Angola with the prize on Kalimba as our new prospect, so...

So for gas, so you're right -- correctly that they are going to lose some subsidies on the end customer. For us, it's completely different. We have a contract, long-term contract for our gas sales, and we have prices that are contractual prices, on which we are -- recover our cost, and as you know as -- oiling but with the floor and the ceiling, so we cannot go down more than some prices, and we can roll following the oil price. We have an area. We respect that. He's also represented a securitization for us for the future. So this kind of increase of price are not touching the upstream side.

The next question is from Bertrand Hodee of Kepler Cheuvreux.

I have two if I may. The first one on your new discovery on Block 15/06, you mentioned that it was close to existing infrastructure, but it's like 55 kilometers away and you intend to make a fast track. So I imagine it's going to be a tieback as probably one of the longest tieback. Is it feasible? That's my first question, and the second question is about also FID contemplated this year. So you -- we've already talked about Mexico [indiscernible]. And -- but can you give us an update on Congo Nené Marine Phase 2b, where do we stand? And also on Egypt Baltim South West.

Antonio Vella is going to answer the two questions.

Okay. Concerning the Kalimba tieback, we will call a tieback because we are patented already our technology concerning the longer extension tieback in the water, and will be implemented in Kalimba, which will allow us to go above 65 kilometers for the time being. So this is going to be a development of between 5 to 7 wells. Concerning the -- so the delivery of the oil are so long distance that we have a multiphase pump on the water, which will allow to produce all the volume directly to 1 of the 2 FD, so actually, in production. Reference to the other question of the FID of Kalimba, we'll have an FID in -- by the end of the year. And the next -- the other question was the FID of Nené 2b, it's planned for this year, and we are completing all the marketing bids, and is expected to make it by the fourth quarter of 2018. So the other issue is of Baltim South West tieback. So Baltim South West is already -- the FID has been made, and is under construction, and will be in production next years. The production -- the increase between great Noroos and Baltim will rise up the actual 2 billion or 200 scrap per day to 1.9 billion scrap per day. I think concerning the other development and FID of Merakes in Indonesia, we are going to finalize the FID within the fourth quarter of 2018. It's going to be a tieback also in Jangkrik FPSO.

The next question is from Massimo Bonisoli of Equita.

Thank you for taking my two questions, the first is on Gas & Power. Considering the strong results in the first half, the new outlook for the division implies some decline of operating profit in second half compared to second half last year. Could you give us some color on the evolution of EBIT in second half, and do you have some contingencies in the outlook? And the second question is if you can give us some indication on the working capital evolution expected in second half just for our models?

Okay, Massimo Mondazzi will answer.

The first half benefit of -- in respect of LNG, was very high price on the Asian markets. And thanks to the integration with upstream, we manage also to increase and to sell more of the production of Jangkrik, in particular. It was an extra production, which is expected this year of 1 million, more than what actually what we were envisaging. And most of the LNG activity, of course, has been locked in or in the first semester in respect of the second half to be sure that we were taking the benefit of the market scenario. In respect, and there is one thing which may be of interest that please also consider, which is not a regular question, that we have an increase of the equity market in [indiscernible]. 54% of the marketing was actually equity LNG as compared to only 25% of last year. In respect of power, we also benefit in the first semester of a very good outlook in respect of the clean spark spread, which is expected a little bit lower in the second half. In the first half, we also benefit of the [indiscernible], which as you know has been sold at the end of June, and will not in the second half. But for the time being, we are setting the guidance overall for the Gas & Power sector at €400 million. However, of course, we will be looking for further increase.

Okay, Massimo, in terms of working capital trend, in the second quarter, we released more or less €250 million out of the €900 million absorbed, you remember, in the first quarter. The expectation would be to release the rest, so to recover the remaining €700-plus million, we still expect a positive contribution of working capital by the end of this year.

The next question is from Mr. Theepan Jothilingam of Exane BNP Paribas.

I had a few questions, actually. Firstly, could you talk a little bit about how much contingency you have left into the upstream volume forecast for 2018? I'm trying to understand how derisk sort of underlying cash flows are for the second half of this year. The second question I wanted to ask was just how do you put the leverage ratio and the appetite of buybacks vis-à-vis aspirations to broaden a downstream footprint?

Antonio can talk about contingency and the -- that we have up to the end of the year.

So we have 20,000 barrels boe of contingency for the next six months. And as you have seen, our 1,865,000, this moment, we will have just a few shut down during the next six months, and hopefully, we can recover part of this contingency.

Okay. Thank you. So the question is what I understood, the output against the buyback against a possible downstream acquisition or organic growth in the downstream. So the answer is very clear. There's no -- they are not in competition. So we have space for both and there's no competition between a possible buyback if we have the right condition, and the possible increase in our refinery capacity on the right conditions at the right place with the right margin, so the two things can stay together.

The next question is from Mr. Jason Gammel of Jefferies.

I just want to come back to the Vår Energi transaction which looks very interesting. I was hoping to ask more about Corporate Governance and will the entity act essentially fairly autonomously with you having board members? Or will you have a little more direct oversight into their operations? And then also, will this be essentially a self-funding entity? Or it will require ongoing capital injections from the parent? And then I guess the flip side of that was when would you expect to be able to receive dividends from Vår?

So definitely, we'll try to answer all your questions. So no capital contribution expected, so the company is so strong that they definitely they can go ahead funding the capital -- the CapEx plan without any kind of contribution. Anyway, the company should definitely should finance by itself, the future CapEx. In terms of governance, the governance is very well-balanced, take into consideration the 30%, 70% in terms of shareholding. So definitely, we will have the majority in the board, but the exceptional decision, definitely, they require the unanimous decision because, definitely, the 30%, 70% participation -- participating interest. Definitely, about the dividend, yes, I already said that the capital structure is really strong, and there is already production. So the cash flow could be distributed to the shareholders since the beginning of this new venture.

The next question is from Mr. Biraj Borkhataria of Royal Bank of Canada.

Just two quick follow-ups, please. The FID in Mexico, I believe, that was originally expected in the first half of '18. Could you just confirm that production -- first production is still on track for early 2019? And then second question is on the Noor Prospect. Earlier in Q2, there were some conflicting reports on whether you completed the well or not, and it sounds like it's still ongoing. But could you talk about -- just give a bit more color on the prospect side and the potential there.

Okay. As you know that our prediction on the POD approval was a little bit optimistic. But unfortunately, today, the POD approval of Mexico is going to be in weeks from now. So the first production is confirmed within first half of 2019.

Regarding Noor, as you see, we didn't comment on all the noise that come out on the press. Noor prospect is still a prospect. We didn't start drilling. We will start drilling most likely in September, October this year.

The next question is from Rob West of Redburn.

I've got a couple. First, I'd like to go back to Gas & Power. So you phrased the guidance for 2018. I was wondering how the change there impacts the guidance towards the end of the plan, so that the ramp to €0.8 billion. Just what you're saying -- just give me more confidence? Or what has to happen to translate through some upside to that numbers as well? The second question I wanted to ask is about restarting the LNG assets in Egypt, so Damietta. Can we have an update on what's the hold up there in terms of what do you still need to agree? I think last quarter, you said it was something that could happen quite soon. So I was wondering if there was any update as Zohr continues ramping quite nicely.

In respect of the plan, I think that we will revert to this when we have the strategy at the beginning of the year. However, of course, the situation of the Gas & Power is something which puts us more confident in respect of what we are doing. In respect of the mid-term, and you know that in respect of the mid-term, Union Fenosa Gas, there are ongoing arbitration between the Egyptian side and the Union Fenosa Gas. However, has been going on commercial discussions, and I do believe that not only it's in the interest of all parties involved, to reach an agreement. But from my perception, all parties are working hard on the possibility to reach an agreement on this. Of course, the discussions are ongoing.

The next question is from Jon Rigby of UBS.

So I have a few, actually. The first is, obviously, cash flow benefited from some deferred consideration now starting to come through, which actually came in about a quarter ahead of where I've been modeling. But I guess that prompts the question, is there any more deferred consideration still to flow through on announced transactions, please, just so I get that right? The second question is just on Kazakhstan. I'm just looking at the liquids production in Kazakhstan, it seems to be flat year-over-year and sequentially, and I thought with cash again ramping up, I was a little puzzled about this. So can you just explain the moving parts on that, I guess, maybe something to do with Karachaganak? And the third is I'm still like a little puzzled on the Gas & Power number. I know you sort of talked to this, but can you just go through 1H to 1H, the moving parts sort of decomposed by the various contributors to the [indiscernible] operators differentiate, so I could understand how we've got to where we've got to in 1H '18 over 1H '17, if that's possible, please.

So Jon, in terms of part of cash-in from disposal already done, the answer is yes. There will be -- the last one, first half of '19, but would be, I will say, minor, minor value.

Kazakhstan?

Yes, okay. So Kashagan, we have reached the production of 424, which is 380 -- 338 oil in last June. So the EPC, as you know, has been commissioned in the beginning of the year, and now it's contributing with additional 7 wells. The average equity in 2018 will be 61 barrel oil equivalent with a clear contribution on the ramp up, which we expect by the end of the year, the 350,000 barrels of oil.

So is Karachaganak running below? Or is there some [indiscernible]

No, no, Karachaganak is running very well. We keep stable the 250,000 barrels liquids. And we are progressing for FID of the remaining project to keep longer, the extension of 250,000. We got a record last year, as you remember.

Sorry, Jon. But your impression is that -- what happened there, there is no -- in spite of the growing production in Kashagan, you see a steady production in [indiscernible] in Kazakhstan, that is your question?

Yes.

Yes. So we have Karachaganak steady, but we have also maintenance. So during the year, you saw sometimes that the Kashagan production was down, and the increasing in Kashagan rebalance this, and at the end, it seems it looks that steady, but Karachaganak is steady and Kashagan is ramping up. Then there is the game, the game of the maintenance can maybe confuse if you look out the future. But in the long term, the situation is that.

For Gas & Power, if I look at the first half of last year and half of this year, where -- the area where we are more pleased about how things went, well, the first one is actually LNG. Also, if you take into account that if we do not consider a retroactive effect on LNG that we had last year, the improvement this year was quite significant. As I say, there was also a significant increase on the volume and the integration, in particular, with our equity production in Jangkrik was extremely important in this respect. A second area of key difference is also power. That is mostly because the clean spark spread view of this year, the scenario was better -- significantly better than the other year, and the third area where we can look at the difference between the two half is, actually, there of logistic of gas and gas supply cost overall which had a significant improvement. And so those are the three elements, which probably made the difference in respect of this year.

Right. Are you able to sort of decompose that into numbers or something?

Not really. But the weight of the three elements were quite significant. Please consider that, substantially, also, the retail business was in line during the two halves. So the increase is mostly on this area of LNG and the power and gas logistic.

The next question is from Martijn Rats of Morgan Stanley.

I have two. They are slightly more generic in nature. First of all, I wanted to ask if you are seeing any signs of cost inflation throughout your upstream businesses. It's one that on the whole, we'd be sort of quite interested in. And secondly, given your position in Venezuela, I was wondering if you had any sort of thoughts on the country, any observations from the ground, so to say?

In terms of cost inflation, what we can say is that we see some increase of steel raw material that is mainly affecting the cost of line pipes. Regarding the rest of the activity for upstream, we don't see particularly changing the offshore drilling unit market with very -- no significant increase in rate. What we can see instead is the increase of the utilization of the drilling units that offshore has reached 65%, as we can see in the last quarter, but without a direct increase in terms of daily rate. For the rest of the agreement for subsidy development, the global demand is still lower than the capacity of supply. So we don't see in the short term change in terms of cost for development.

So Venezuela, we can just say from our position, and from an operating point of view, we have some -- we got some very -- some good positive signs because we -- after our discussion, we're getting some money back. So they are paying the gas that we are producing for the first time in the last month. So for the first six months has been, we can say, positive because they paid. So our securitization, again, that we are in place -- are restarting -- working again. So that is what I can say.

The next question is from Lucas Herrman of Deutsche Bank.

Claudio, I wonder if I could push you a little more on the comments you've made on downstream assets, and certainly seems to have made your institutional clients around the desire to expand or potentially expand your downstream presence, not least in the Middle East. I mean, just to push into sort of the strategic rationale of a move in that position and how much capital, perhaps, you're willing to put at risk, I mean, the strategy and the thrust is very much being upstream. I appreciate observations around balance. But if you could just give us a better sense of what you're trying to achieve and how much you're willing to put at risk to achieve it.

Thank you for the questions. Clearly, what we want to achieve is to have a -- to be a long the value chain. So when we have upstream, we'd like to have some downstream to really to call the value chain, and also to be -- to have some -- to be able to counter-balance the price situation that happened sometimes in the last -- that was a -- three, four years. So we talk about growing, growing at which conditions. First of all, we want to be able also, growing in the downstream to be able to reduce as a target, our cash neutrality because the, as you saw, as we experienced during the low price, when you have a downstream that is a good one. So with good margin, that can increase, can really increase your profitability and can reduce your cash neutrality, and that is my target. That, on the contrary, is going to give me the freedom to invest more in downstream, and that is what I want to achieve. Clearly, I like to have integrated project, so I don't -- we are not looking for downstream for the sake to have more downstream. But where we have production, we'd like to have some stake in the downstream. And with aim, and that is 1 of the 2, that we want to use, to reduce our cash neutrality. As I said before, in terms of investment, the investment will be really in line with our capability to have a strong balance sheet, a low leverage, the possibility to as -- we have as a priority, the capital allocation to pay our dividend and in the future, the buyback. But we'll also be able to invest to increase a good downstream to reduce our cash neutrality.

So if I think of scale, given, I guess, we're talking about the UAE or Abu Dhabi, where you'll be producing from recollection, 80,000-odd barrels a day, is that the level of integration you want, i.e., top bridge of what comes up?

The land integration is related to the value. So it's not just the volume that -- we don't have a target in volume, but we have the target in value and in terms of cash neutrality. So it's a balance. It's a material balance that we have to do every time. So it's linked to the economics and to the value that we are going to create. Based on the last studies and feasibility we made, we were discussing our target, was to have about 200,000 and 400,000 barrels per day additional in the four-year plan. So that is something that we are working on and this is -- some thing's organically and other is not organically.

Sorry, just to be clear, that's 200,000 to 400,000 incremental barrels of refining capacity, both organic and inorganic?

Yes. In the four-year plan, that's what we said during the -- our strategy. And that is clearly linked to the value that we're going to create and the impact on our cash neutrality.

The final question is from Kim Fustier of HSBC.

I had a couple of questions, please. Firstly, I wondered if you could offer any color on that deepwater Black Sea drywall that's part of your Rosneft JV? I think you own 1/3 of that JV, and the write-down for that dry well was €200 million. So could you perhaps confirm what was the growth cost of that well? And also what your intentions for that Rosneft JV are going forward? Secondly, I think you and your partner, Exxon, made some comments recently at a gas conference in the U.S. about progress on marketing of the Mamba LNG volume. So I wondered if you could share some of that color with us and also if you're still aiming for FID in late 2019 or early 2020.

So on the first question about Russia and the joint venture, you know that these activities, deep water activities, Barents Sea, Black Sea are under secondary sanction, U.S. secondary sanction. So clearly, there's no space for us to go ahead with this joint venture. And for the Gas & Power?

For Gas & Power, in respect of our Mozambique LNG future production, you're right. There was actually, a marketing meeting, which we had in Washington, D.C. with all the partners involved in the project, and not only Exxon, but also the others. And we all agreed that, basically, marketing will not be a critical element, so that everybody's ready to offtake the production and to ensure that the final investing decision is taken, irrespective of the fact that all the LNG has been sold to third parties. Some of these LNG will go in the portfolio. Some will be sold, but nevertheless, pro rata, all the partners are ready to take it up.

There's another question from Ian Mitchell of JPMorgan.

Yes, it's Ian from JPMorgan. Just two quick ones, hopefully. You've talked quite a lot on Gas & Power, and we've heard about the improvements you've had in equity volumes of LNG, and then spark spreads in power. Are either of those sustainable structural changes? Would we expect better spark spreads next year versus what you're expecting earlier on this year, and if so, why? And then the same in terms of the LNG volumes. Should we be considering that there's some longevity to this improvement? And the second one is on Mexico. You've given us some details on the POD. Has there been any change at all in terms of tone or your discussion since the election? And given that you're on the ground, have you got any additional information as to how the new government might look at the oil and gas sector relative to what you're dealing with prior to the election?

Yes. On the Gas & Power, just two elements in respect of what you asked. The first one is that, of course, on the power, it does depend a lot on how we see and where it will [indiscernible] spark spread in respect for future, and -- but please do consider also that one key element is the flexibility element of the power production, where we think that there will be some value to gain at. In respect of LNG, also, here, the market scenario was extremely significant in the first half, which allow us to lock in the volumes we had. But as you underlined, it was interesting, the increase of production, which we -- our upstream part to manage what we have on the Jangkrik field, and we do believe that the volumes, which we are allowed to put in our portfolio, as I see said, it's extremely important to increase that volume, which is working very well this year. And we are working on that in conjunction with our upstream colleagues. And this is something, which we will be looking at, in particular, when we present a new strategy.

Okay. Concerning Mexico, we've been working, as I told you, that very, very well with the authority, and we identify the plan of development jointly. And as far as election, we didn't notice any changes and the cooperation is still going. And as I mentioned, in a week's time, we expect to have the approval of the FID.

Gentlemen, that was the final question. Thank you for participating in the Eni Conference Call. You may disconnect your telephone.