Good afternoon, ladies and gentlemen, welcome to Eni's second quarter results conference call hosted by Mr. Claudio Descalzi, Chief Executive Officer. For the duration of the call, you will be on listen-only mode. However, at the end of the call, you'll have an opportunity to ask questions by pressing star and one on your touch-tone telephone. I will now hand you over to your host to begin today's conference. Thank you.
Good morning, welcome to Eni's first half results. The first half results confirm the strength of our industrial performance. Upstream production was more than 5% higher versus 2017, considering the PSA effect. Growth was sustained by the contribution of major ramp-ups, such as Zohr and Kashagan, and the start-up of Ochigufu in Angola and Bahr Essalam phase 2 in Libya. Exploration continued to deliver great result. During first half, we drilled seven successful wells for a total resources of 280 million barrel at an exploration cost of $1.4 per barrel. We announced a strategic step in Norway with the creation of Vår Energi. Moving to Gas and Power, the structural change we have implemented in the past four years allow us to achieve a strong performance, increasing EBIT to EUR 430 million, more than doubling 2017 result.
Downstream businesses impacted by weak scenario confirmed their resilience with an overall EBIT of almost EUR 150 million. Moving to financials, operating and free cash flow growth are the most remarkable achievements. In summary, the first half, we generate EUR 6 billion of operating cash flow, a 22% growth versus 2017. CapEx was reduced by 14% to EUR 3.7 billion. We generate an underlying free cash flow before disposal of EUR 2.3 billion, largely exceeding the EUR 1.5 billion of interim dividend paid in this period. Thanks to this strong cash performance, we reduced our net debt to below EUR 10 billion, the lowest level reached since 2006. This corresponds to a leverage of 20% at the end of June and a gearing of 16.4%. Before detailing the result of each business, I would like to give a more color on Norway.
We agreed with the private equity, HitecVision, to merge Point Resources into Eni Norge, 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 barrel per day this year. Vår Energi has 17 producing oil and gas fields and more than 500 million barrel proven reserves. Building on the existing organization and leveraging complementary strength, we will grow production through a pipeline of 10 already existing project to 250,000 barrel per day by 2023. In total, the company will focus over the next five years on bringing projects on stream, revitalizing 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 barrel in place of high-quality light oil, with an estimated production rate per well exceeding 5,000 barrel per day. This discovery will open new opportunities for oil exploration in the southern part of the block, which has thus far been considered mainly a gas area. We plan to appraise the discovery and to take 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 kilometer away. In Egypt, we made two oil discoveries in South West Meleiha in the western desert. These discoveries tested the deep geological sequences of the Faghur Basin, a new exploration play. During the production test, the wells delivered more than 5,000 barrel per day. These Egyptian discoveries, together with other prospects that will be drilled in this basin this year, will rely on fast drilling phases, low costs, and synergies with existing facilities. This will accelerate our growth in this new production area, where we are already producing about 53,000 barrel per day. Finally, we achieved important results also in new areas.
In Area 1 in Mexico with the Tecoalli-2 and the Amoca Deep, and in Cyprus with the offshore discovery of Calypso, a lean gas discovery which proved the extension of the Zohr-like play within the Cyprus exclusive economic zone, where the joint venture is now working to prepare the appraisal plan. A quick look at production results. Production in the first half reached 1,865,000 barrel per day, 5% higher than last year. We had a positive performance from ramp-ups and start-ups, mainly in Egypt, Indonesia, Angola, Ghana, Congo, and Kazakhstan, contributing 263,000 barrel per day. On the other side, we had some production reduction due to a major maintenance program in Nigeria and in Libya, where the downtime was higher due to the tie-in of Bahr Essalam's phase 2 wells and the natural depletion in some fields in the U.S. and U.K.
We confirm a production growth of 4% in 2018 at budget scenario. We achieved an EBIT of EUR 4.83 billion, more than doubling last year's result due to scenario effect for EUR 2.1 billion, better production performance for around EUR 500 million. Let's now have a look at Zohr, where ramping up is proceeding faster than planned. After the start-up of the first train in December 2017, we added four new treatment units. Each production unit has an average production capacity of 400 million scf 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 translated 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 at €3.2 billion in the semester, Eni generating 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 $13.5 per barrel over last year.
Excluding.
I'm sorry, yes, EUR 2.3 billion, excluding disposals, not including, yes. Excluding. Gas and Power's EBIT has doubled versus last year with a steady retail contribution of around €113 million. The strongest improvement is related to midstream, where EBIT increased by nearly €250 million. Looking detail in the midstream growth, €70 million was related to higher LNG volume, 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 result and the remaining amount to logistics, efficiency, and contract renegotiations. Taking into account the result achieved until now and the seasonality of Gas and Power performance during the second half, we improve our yearly EBIT guidance from €300 million to around €400 million. Downstream was impacted by the challenging scenario of 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 procurement margin to our $3 per barrel level. In particular, we will further optimize logistics and operational costs through integration and efficiency, complete our biofuel plant in Gela by the end of this year, and restore the EST plant at Sannazzaro, and consolidate our marketing position in Italy. In the chemical sector, the scenario has been characterized by some negative factors. High cost of virgin naphtha occurred in second quarter, not yet entirely reflected in the product prices, and an excess of supply in the European polyethylene market due to higher export from the U.S.
Notwithstanding these very difficult conditions, our result was positive, with an EBITDA of EUR 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 a continuous focus on operational performance and higher product prices. Considering this rebalance of the market, thanks to the positive contribution of the industrial and marketing action, we now forecast for the downstream and the overall EBIT of more than EUR 500 million, of which EUR 330 million is from R&M and EUR 180 million from Versalis. Looking at our consolidated results, thanks to the strong cash generation achieved in the first half, taking into account the disposal, cash-in, and the dividend payment, the net debt for the first time since 2006 is below EUR 10 billion, and our leverage is at 20%.
In terms of full-year guidance, we will generate a cash flow from operation of more than EUR 13 billion, which includes a minor contribution from working capital and the cash-in related to 2017 disposal. With CapEx around EUR 7.6 billion, underlying free cash flow before disposal is expected to be EUR 6 billion, a 40% growth versus our original plan. This confirms our capability to more than capture the upside related to the improvement in the scenario. We confirm the cash neutrality of $55 per barrel. Now with Massimo and the management, we are ready to answer your questions. Thank you.
Ladies and gentlemen, we will now begin the question-and-answer session. The first question is from Oswald Clint of Bernstein. Please go ahead, sir.
Yes, thank you. Good afternoon. I want two questions, please. The first one, just on your last few comments on leverage, just almost reaching the 20% level at the end of June. I think in the strategy there you spoke about balancing strength in excess of that or below the 20%, you would talk about buybacks and the potential for those. Maybe you could just update us on that number, where it might progress, and ultimately what that means for that possibility of buybacks, please. 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 potential with the gas supply agreements, maybe upstream and Gas and Power benefits here from that deal.
I just wonder if you could talk about that set of negotiations, please. Thank you.
For the first point, the buyback, once we reach or we are below the 20% leverage, I can just confirm what we said during our strategy presentation. We said that once we are below the 20%, considering the scenario, we are steady below the 20%, we can consider and propose to our board a buyback, that is inside our policy, our remuneration policy, that is confirmed. For Algeria, yes, we signed two different agreements. The agreement is a general agreement that aim to reduce cost because we have several activities in Algeria. We agreed with Sonatrach to put all this activity and merge all this activity under just one umbrella and create strong synergy and reduce cost, operating cost. That has been done, is in progress, and with good result.
We final agreement on the gas because we have gas in Algeria that produce as associated gas, and we have gas in the underneath level where we produce oil. We sign an agreement to export this gas that we produce in the south to our facility where we treat gas in Emili and Cac from the BRN field where we produce this gas, that will be an additional improvement in terms of efficiency, in terms of resource, in terms of quantity of gas that we can deliver. Another formal decisions in Algeria is that we are replacing in our activities, and also in the future in Sonatrach
The gas that we use for internal consumption with renewables, in this case, with solar or photovoltaic, that makes additional gas free for export or for domestic consumption.
Very clear. Thank you.
The next question is from Thomas Adolff of Credit Suisse. Please go ahead.
Good morning. Two questions for me, please as well. Firstly, congrats on the deal in Norway. Hopefully, life gets a bit easier and better now. 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, a bit less to do with what upside you may see on refining. I'm just more interested in the type of crude that you have, that you produce in the upstream. The overall crude gravity and sulfur level. In an IMO world, would Eni's price realization improve or worsen versus what you see today? Thank you.
Thank you. The first question will be answered by Mass, the other from-
Thomas, the effect is due to the different timing in terms of cash flow from operation versus CapEx. That's the reason why we will record an improvement in our cash neutrality by 2019 of around $2. We expect, thanks to the investment, production growing to 250. That will be the final result. All this based on existing projects already clear, very well identified in our portfolio.
Thank you, Thomas, for the question. As we already mentioned in several other occasions, Eni will be able to satisfy the requirements of the IMO to resolve production, capable of achieving a zero production of fuel oil. This is due to the fact that we are a highly conversion system. We explore the EST, that, as you know, is on the phase of rebuilding in Sannazzaro. The RHU, that is a residue hydrotreating unit in Taranto, and the Milazzo refining, plus system integration. On this aspect, let me also emphasize that we just restarted the Taranto refinery that was offline to allow the work to make the plant able to refine also the Tempa Rossa crude, that is a 10 to 22 degrees in gravity. In general, we don't expect our slate to lighten in the coming years.
On average, we have a slate that is about 30 degrees API in density.
Yeah, I was just more interested in your actual upstream production, not what crude you process in the refineries. 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. I wondered what dynamics we should see in Eni's upstream price realization.
One second. We are checking the few data. I can start giving a qualitative answer, and then we talk about figures. Our average crude production in the upstream is light, so is light oil with a very low sulfur content. I think that from generally speaking, not just talking about our refineries, but all the different refineries 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 let you have the differential end of March that can be listed.
This is great. I just wanted to know that you will benefit from it.
Yeah. Sure.
Thank you.
Thank you.
The next question is from Irene Himona of Societe Generale. Please go ahead, ma'am.
Thank you. Good morning. I had two questions, please. First of all, on Gas and Power, obviously a very strong result, and you're increasing your guidance for this year. Back in March, in the strategy 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, Claudio, 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 CapEx above the EUR 32 billion you budget for the next four years? Thank you.
Alberto can give you some color about retail gas or Eni gas e luce, and the trend and the result in the future.
Yeah. Thank you. In terms of results of the first half of Eni gas e luce, the results were quite strong. We reached EUR 140 million of EBIT overall. 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 EUR 200 million of EBIT.
Thank you.
Considering the second question that is related to when we can think to increase our CapEx because we have so many resources and we think that the price now is stable, or we can go and we need additional production. If you look what we have done in the last four years, we never reduce our growth on our investment. We try to have a different kind of attitude or approach to be able to increase our production, reducing our CapEx, and without leaving behind us any kind of projectable opportunity. We develop everything.
Zohr has been developed with a very. In a price scenario that we were an average of $40 per barrel, we took a commitment of EUR 12 billion, at the end, what happened that through our exploration, we are able to reduce our in-house capital, we reduced our exposure, and we can continue to develop. From one side, we have an organic growth starting from exploration low cost. An upstream that at a very low cost, well, we don't need a lot of investment. We don't have complex, super complex, and mad project that requires us to put a lot of money. We learned. We know everything about that. In the last four years, we changed. Low CapEx because our cost, our overhead is low.
Secondly, we use another tool that they do an exploration to reduce our exposure without leaving underground our opportunity in the oil and the gas. I don't think that also with a higher, we can say, higher price with the kind of asset we have, we are obliged to invest more. I tell you that this $55 cash neutrality, $50 cash neutrality, this area of cash neutrality for us is a must. It's a must because the only way to be able to face any kind of environment, it's a must also because we use a model, and we use a philosophy and approach that allow us to invest because our costs are low, and we have to do an exploration to spread and reduce our investment risk. The answer is, we are going to continue to grow. We are 3.5% this year.
It's 4%, we'll be 3.5%, maybe we'll be more in the future, we want to be really strict and disciplined and use a strong discipline in terms of cost and capital allocation.
Thank you very much, Claudio.
Next question is from Alessandro Pozzi of Mediobanca. Please go ahead, sir.
Thank you for my questions. 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. 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. Thank you.
For Mexico, Antonio can say something about the future development and exploration, looking then I can say something about Zohr and gas prices.
Okay. As you know that we've been working with the authority in the last couple of months to finalize the POD. Everything has been completed, and in a week's time, we expect to get the approval. Then immediately on the third quarter, we will have FID. This is all on Mexico.
On exploration, the 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. 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 project Kalimba and some new prospects also. For gas, Claudio, you read correctly that we are going to remove some subsidies on the end customer. For us, it's completely different. We have a long-term contract for our gas sales, and we have prices, there are contractual prices on which we recover our cost.
As you know, as oil-linked, but with the floor and the ceiling, we cannot go down more than some prices, and we cannot go following the oil price. We have an area of respect that is also represented the securitization for us for the future. This kind of increase of price are not touching the upstream side.
Thank you very much. The next question is from Bertrand Hodee of Kepler Cheuvreux. Please go ahead, sir.
Yes. Hello, thank you for taking my question. I have two, if I may. The first one on your new discovery on Block 1506. You mentioned that it was close to existing infrastructure, but it's 55 km away, and you intend to make a fast-track. Imagine it's going to be a tieback. It's probably one of the longest tieback. Is it feasible? That's my first question. The second question is about the other FID contemplated this year. We've already talked about Mexico Area 1. Can you give us an update on Congo, Nené Marine Phase 2B, where do we stand, and also on Egypt Baltim Southwest? Thank you.
Antonio is going to answer the two questions.
Okay. Concerning the Kalimba tieback, we will call a tieback because we have patented already our technology concerning the longest tension tieback underwater, and will be implemented in Kalimba, which will allow us to go above 65 kilometers for the time being. This is going to be a development of between five to seven wells. The delivery of the oil, solar distance, we have a multi-phase pump underwater, which will allow to produce all the volume directly to one of the two FPSO actually in production. A reference to the other question of-
FID
the FID of Kalimba, we'll have an FID by the end of the year. The other question was the FID of Nené Marine. It's planned for this year, and we are completing all the marketing bids, and it's expected to make it by the fourth quarter of 2018. The other issue is of Baltim Southwest tieback. Baltim Southwest, the FID has been made and is under construction and will be in production next years. The production will increase in between Great Nooros and Baltim will rise up the actual 2 billion or 200 SCF per day to 1.9 billion SCF 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 FPU.
Many thanks.
The next question is from Massimo Bonizzoni of Equita. Please go ahead, sir.
Thank you for taking my two questions. The first on Gas and Power. Considering the strong result in 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, do you have some contingencies in the outlook? The second question, if you can give us some indication on the working capital evolution expected in second half, just for our models.
Okay, Massimo. Want to run with Milani.
The first half benefits of, in respect of LNG, of very high price in the Asian markets. Thanks to the integration with upstream, we managed also to increase and to sell more of the production of Jangkrik, in particular, as an extra production, which is expected this year of 1 million more than what actually we were in this agenda. Most of the LNG activity, of course, have been locked in already in the first semester in respect of the second one, to be sure that we were taking the benefit of the market scenario. There is one thing which may be of interest that please also consider, which is not related to the question, that we had an increase of the equity marketed by us of 54% of the marketing was actually equity LNG, as compared to only 25% of last year.
In respect of power, we also benefited 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 CDT, which, as you know, has been solved at the end of June and will not be in the second half. For the time being, we are setting the guidance overall for the Gas and Power sector at EUR 400 million. Of course, we will be looking for further increase.
Okay, Massimo. In terms of working capital turnover, in the second quarter, we released more or less EUR 250 million out of the EUR 900 million absorbed, you remember, in the first quarter. The expectation would be to release the rest. To recover the remaining EUR 700-plus, we still expect a positive contribution working capital by the end of this year.
Clear. Thank you.
The next question is from Mr. Theepan Jothilingam of Exane BNP Paribas. Please go ahead.
Yeah, hi. Good afternoon, gentlemen. I had a few questions, actually. Firstly, could you talk a little bit about how much contingency you have left in sort of upstream volume forecast for 2018? I'm trying to understand how de-risked 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 for buybacks vis-a-vis aspirations to broaden a downstream footprint? Thank you.
Claudio, can talk about contingency that we have.
After the end of the year.
We have a 20,000 BOE of contingency for the next six months. As you have seen, our million 865, at this moment, we will have just few shutdown during the next six months, and hopefully we can recover part of this contingency.
Okay, thank you. For the question, if I well understood, you are putting against the buyback, against a possible downstream acquisition or organic growth in the downstream. The answer is very clear. There is no, they are not in competition. We have space for both, and there is no competition between a possible buyback if you have the right condition and a possible increase in our refinery capacity at the right conditions, at the right place, with the right margins. The two things can stay together.
Thank you. Very helpful.
The next question is from Mr. Jason Gammel of Jefferies. Please go ahead.
Thanks very much, gentlemen. I just want to come back to the Vår Energi transaction, which looks very interesting. I was hoping to ask more about corporate governance. Will the entity act essentially fairly autonomously with you having board members, or will you have a little more direct oversight into their operations? Then also, will this be essentially a self-funding entity, or will it require ongoing capital injections from the parent? Then I guess the flip side of that is when would you expect to be able to receive dividends from Vår Energi?
Definitely try to answer all your questions. No capital contribution expected there. The company is so strong that definitely they can go ahead funding the CapEx plan without any kind of contribution. Anyway, the company definitely should finance by itself the future CapEx. In terms of governance, the governance is very well balanced, taking consideration of the 30%/70% in terms of shareholding. Definitely, we'll have the majority in the board, but the exceptional decision, definitely they require the unanimous decision because definitely the 30%/70% participating interest.
Definitely about the dividend. Yes, I already said the capital structure is really strong, and there is already production. The cash flow could be distributed to the shareholder since the beginning of this new venture.
Very helpful. Thank you.
The next question is from Mr. Biraj Borkhataria of Royal Bank of Canada. Please go ahead.
Hi, thanks for taking my questions. Just two quick follow-ups, please. The FID in Mexico, I believe that was originally expected in the first half of 2018. Could you just confirm that first production is still on track for early 2019? The second question is on the Noor prospect. Earlier in Q2, there were some conflicting reports on whether you've completed the well or not, and it sounds like it's still ongoing. Could you talk about, just give a bit more color on the prospect side and the potential there? Thank you.
Okay. As you know, our prediction on the POD approval was a little bit optimistic. Unfortunately today the POD approval of Mexico is going to be in weeks from now. The first production is confirmed within the first half of 2019. Regarding Noor, as you see, we didn't comment on all the noise that came out on the press. Noor prospect is still a prospect. We didn't start drilling. We will start drilling most likely in September or October this year.
The next question is from Rob West of Redburn. Please go ahead, sir.
Hello, I've got a couple. First, I'd like to go back to Gas and Power. You've raised the guidance for 2018. I was wondering how the change there impacts the guidance towards the end of the plan, the ramp to EUR 0.8 billion. Does what you're saying just give you more confidence? What has to happen to translate through some upside to that number as well? The second question I wanted to ask you is about restarting the LNG assets in Egypt, 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. I was wondering if there was any update as Zohr continues ramping quite nicely. Thank you.
In respect of the plan, I think that we will revert to these when we had the strategy at the beginning of the year. However, of course, the situation of the Gas and Power is something which puts us more confident in respect of what we are doing. In respect of Damietta, and you know that in respect of the Damietta and Union Fenosa Gas, there are ongoing arbitration between the Egyptian side and Union Fenosa Gas. However, have been going on commercial discussions, and I do believe that not only is in the interest of all parties involved to reach an agreement, but for 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. Please go ahead.
Thank you. A few, actually. The first is, obviously, the 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. I guess that prompts the question, is there any more deferred consideration still to flow through on announced transactions, please? Just so get that right. The second is a question just on Kazakhstan. I was just looking at the liquids production in Kazakhstan. It seems to be flat year-over-year and sequentially, and I thought with Kashagan ramping up, I'm a little puzzled about it. Can you just explain the moving parts on that? I guess there's maybe something to do with Karachaganak. The third is, I'm still a little puzzled on the Gas and Power number.
I know you sort of talked to this, can you just go through 1H to 1H, the moving parts sort of decomposed by the various contributors to Gas and Power? Because they are very sort of differentiated. Just so I can understand how we've got to where we've got to in 1H18 over 1H17, if that's possible, please. Thank you.
Jon, in terms of part of cash-in from disposals already done, the answer is yes, there will be the last one first half of 2019, will be, I would say, minor value.
Right. Kazakhstan?
Yes. Okay. As Kashagan, we have reached the production of 424, which is 380
338 oil in last June. The APC, as you know, has been commissioned in the beginning of the year and now is contributing with additional seven 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 barrel oil.
All right. is Karachaganak-
Yes
running below or is there some-
No, no. Karachaganak is running very well. We keep stable the 250,000 barrel liquids, and we are progressing for FID of the remaining project to keep longer the extension of 250,000. We got the record last year, as you remember.
Go ahead.
Sorry, Jon, your impression is that there is now a grow, in spite of the growing production in Karachaganak, you see a steady production in Kazakhstan? That is your question?
Yeah.
Yeah. We have Karachaganak steady, we have also maintenance. During the year, you saw sometimes that Karachaganak production was down, the increase in Kashagan rebalanced this. At the end, it looks better steady, Karachaganak is steady Kashagan is ramping up. There is the game of the maintenance that can maybe confuse if you look at the period, in the long term, the situation is that.
Okay. All right.
For Gas and Power, if I look at the first half of last year and the half of this year, where are the area where we are more pleased about how things went? Well, the first one is actually LNG. If you take into account that if we do not consider retroactive effect on LNG that we had last year, the improvement this year was quite significant. As I said, 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 significantly better than the other year.
The third area where we can look at the difference between the two halves is actually the area of logistics of gas and gas supply cost overall, which had a significant improvement. Those are the three elements which probably made the difference in respect of this year.
Right. Are you able to decompose that into numbers or something?
Not really, the weight of the three elements were quite significant. Please consider that substantially also the retail business was in line during the two halves. The increase is mostly on this area of LNG and power and gas logistics.
Okay. Thank you.
The next question is from Martijn Rats of Morgan Stanley. Please go ahead, sir.
Yeah. Good morning. Thanks for taking my questions. I had 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 on the whole we'd be quite interested in. 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.
Okay. Good morning. 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 particular change in the offshore drilling unit market with very not significant increase in rates. What we can see instead is the increase of the utilization of the drilling units, but offshore has reached 65%, as we can see in the last quarter, without a direct increase in terms of the rates. For the rest of the equipment, especially for subsea development, the global demand is still lower than the capacity of supply. We don't see, in the short term, a change in terms of cost for development.
Venezuela, we can just say from our position and from an operating point of view, we got some good positive signs because after a discussion, we start getting some money back. They are paying the gas that we are producing.
For the first time in the last month. For the first six months has been, we can say positive because they paid. Our securitization agreement that we are in place are starting, are working again. That is what I can say.
Thank you.
The next question is from Lucas Herrmann of Deutsche Bank. Please go ahead.
Thanks very much. Claudio, I wonder if I could push you a little bit more on the comments you've made on downstream assets and certainly seems to have made to institutional clients around the desire to expand or potentially expand your downstream presence, not least in the Middle East. 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. The strategy and the thrust has very much been 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.
Thank you for the question. Clearly, what we want to achieve is to be along the value chain. When we have upstream, we like to have some downstream to really to cover the value chain. Also to be able to counterbalance the price situation as happened sometimes in the last, not so CapEx, 3, 4 years. We talk about 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 as you saw, as we experienced during the low price, when we have a downstream that is a good one. A 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, can give me the freedom to invest more in the upstream. That is what I want to achieve. Clearly, I'd like to have integrated projects, we are not looking for downstream for the sake to have more downstream. Where we have production, we'd like to have some stake in the downstream. With aim, that is one of the tools that we want to use to reduce our cash neutrality. As I said before, in term of investment, the investment will be really in line with our capability to have a strong balance sheet, a lower leverage, the possibility to have, we have as a priority, a capital allocation to pay our dividend, and in the future, the buyback. We also be able to invest to increase a good downstream to reduce our cash neutrality.
If I think of scale, given, I guess we're talking about the U.A.E. or Abu Dhabi, where you'll be producing from recollection, 80,000 barrels a day.
The level of integration is related to the value. It's not just the volume, we don't have a target in volume, but we have the target in value and in term of cash neutrality. Is a balance, is a material balance that we have to do every time. Is linked to the economics and to the value that we are going to create. Based on the last studies and feasibility we made, we are discussing our target was to have about 200,000 and 400,000 barrels per day, additional in the 4-year plan. That is something that we are working on, and something is organically and other is not organic.
Sorry, just to be clear, that's 200-400 incremental barrels of refining capacity, both organic and inorganic.
Yes, in the four-year plan. That's what we said during our strategy. That is clearly linked to the value that we are going to create and the impact on our cash neutrality.
Okay. Thank you very much.
The final question is from Kim Fustier of HSBC. Please go ahead, madam.
Oh, hi, everyone. I had a couple of questions, please. Firstly, I wondered if you could offer any color on that deep water Black Sea dry well, that's part of your Rosneft JV. I think you own one third of that JV, and the write-down for that dry well was EUR 200 million. Could you perhaps confirm what was the gross cost of that well, and also what's 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 Mozambique LNG volumes. 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. Thank you.
On the first question about Russia and the joint venture. You know that these activities, deep offshore activities, at the Barents Sea and Black Sea are under secondary sanction, U.S. secondary sanction. Clearly, there is no space for us to go ahead with this joint venture.
For the Gas and Power, yes. For Gas and Power in respect of our Mozambique and LNG future production, you're right, that there was actually a marketing meeting, which we had in Washington, D.C., with all the partners involved in the project, not only Exxon, but also the others. We all agreed that basically, marketing will not be a critical element so that everybody's ready to off-take the production, and to ensure that the final investment decision is taken, irrespective of the fact that all the LNG has been sold to third parties. Some of this LNG will go in the portfolio, some will be sold, but nevertheless, pro rata all the partners are ready to take it up.
Okay, thank you.
Excuse me, I'm sorry, there's another question from Ian Mitchell of JPMorgan. Please go ahead.
Hi, guys. Yes, it's Ian from JPMorgan. Just two quick ones, hopefully. You've talked quite a lot on Gas and Power. We've heard about the improvements that 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 were expecting earlier on this year? If so, why? The same in terms of the LNG volumes. Should we be considering that there's some longevity to this improvement? The second one's on Mexico. You've given us some details on the POD. Has there been any change at all in terms of tone or your discussions since the election?
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 were dealing with prior to the election?
Yeah, on the Gas and 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 be, the clean spark spread in respect for future. Please do consider also that one key element is the flexibility element for 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. As you underline, it was interesting, the increase of production, which our upstream partners have on the field.
We do believe that the volumes which we are allowed to put in our portfolio, as I said, is extremely important to increase that volume, which is working very well this year. We are working on that in conjunction with our upstream colleagues. This is something which we will be looking at, in particular, when we present a new strategy.
Concerning Mexico, we've been working, as I told you, very well with the authority. We identified the plan of development jointly. As far as election, we didn't notice any changes, and the cooperation is still going. As I mentioned, in a week's time, we expect to have the approval of the FID.
Okay, gentlemen, that was the final question. Thank you for participating in the Eni conference call. You may disconnect your telephones.