Earnings Call: Q2 2018

Jul 30, 2018

Good morning, ladies and gentlemen. Please welcome to GAP's 2nd Quarter of 2018 Results Conference Call and Strategy Execution Update. I will now pass the floor to Mr. Pedro Dias, Head of Strategy and Investor Relations. Good morning, ladies and gentlemen, and welcome to our Q2's 2018 results conference call. Joining me today is Kairos, who will start with a quick update on our operations during the quarter and our strategy execution achieved so far. As always, we present your full results. At the end of the presentation, Todd will join us, and we will be available to take any questions you may have. I would like to remind you that we may be making several forward looking statements. Actual results may differ due to factors included in the cautionary statements available at the beginning of our presentation, which we advise you to read. Carlos, the floor is yours. Thank you, Pedro, and good morning to you all. We are pleased to present another strong set of operational and financial results. Galp continues to be focused on its strategy execution. In the Q, the EBITDA reached $628,000,000 and our production growth story continues to be supported by higher oil prices and refining performance. More importantly is the cash flow from operations that during the quarter has reached €604,000,000 and after dividends, the free cash flow was EUR146,000,000. The macro context played an important role on these results, but it is also important to highlight the operational performance of our activities and the execution progress of our key projects. Considering where we are year to date and our revision of the market conditions for the second half of the year, we now expect 2018 EBITDA to be over EUR 2,100,000,000. As for CapEx, we are keeping our guidance of €1,000,000,000 to €1,100,000,000 But now also considering the Brazilian bid rounds payment on Catbus Basin 791 block and also Ruiaburu. So actually, it will be a reguideance on the CapEx. I will now briefly go over the performance of our divisions, starting with upstream on Slide 6 of our presentation. So the working interest correction increased Q on Q, and it was supported by the ongoing development on Lula and Viratima, mainly driven by the effort SPX-seven in Mulets House, which has reached the low production plateau in April. We have now all the 7 units running at Quatorial and that surpassed the 100,000 barrels away as a market in Brazil. We will bring online 2 additional units in Lula during this year, which will complete the first stage of development of Lula and Irazina. The FPSO to develop the Lula North area has arrived to the Rio General Bay from China earlier this month. There are still some work to do and the usual regulatory procedure before the unit is placed on its final location. As far as the unit to be developing the Lula Xtreme South area, The integration works are being finalized and the unit is expected to sail to its final location in the coming weeks. Actually, this FPSO might come on stream before Luevenoff-one. Moving now to Angola. The 1st FPSO in Kaombo has started production this last fire, and it is an important milestone for this project. I'll remind you that the development plan for Kaombo comprised its 2 FPSO units, which should more than offset our production decline from our legacy assets currently producing in Guadalupe. All in all, we remain confident that we will deliver on our 2018 production guidance with full year average production 15% to 20% above last year. Moving to the downstream on Slide 7. So refining had a good quarter with high utilization rates and a positive performance. Galp's realized refining margins were $6.1 per barrel. We captured the strong middle distillate cracks during the quarter as well as the slight recovery in gasoline cracks when comparing with the last quarter. Exports to U. S. Also contributed positively with a supportive harbor and Aeroball spread in the quarter. It is also worth highlighting our refining system flexibility to accommodate different raw materials and energy sources, which allowed us to optimize our sourcing and energy costs supporting our margin. In addition, and as you know, we are working to increase the efficiency and the conversion capacity of our refining system, implementing projects to capture an extra dollar per barrel. There is already $0.30 of dollar per barrel of this value on the margin achieved this quarter. As for the marketing activity, it continues to be a stable contributor to results, although our FCA results were impacted by the lag in the pricing from us, driving from a rapid increase in commodity prices. On the Gas and Power, we had rolling salt to industrial clients higher than in the past Q, especially in Iberia. And we also increased traded volumes, even though this was mainly due to lower margin network trading activities, which offset the decline in LNG trading volumes. Now let me take the opportunity to highlight some of our recent key strategic developments, which will enhance our portfolio competitiveness. And I'm on Slide number 8. After acquiring a stake in Block 791 in Campos Basin during the 1st Q, this last quarter, we reached an agreement to increase our exposure to the pre salt with an additional 3% in BMI sales. We will therefore have a fully aligned interest of 20% in both Carcara and NOS of Carcara alongside Equinor and Exxon, each one with 40%. Additionally, in the latest Brazilian bid run held in June, we acquired a 14% index in Uirapuru and also a long time top tier partner. Petrobras, we like as an operator and also with Equinor and Equinor. The interest for these assets was very high, and we are happy with the outcome of this licensee run. We have been very selective in what regards which assets to be poor, and I can assure you that we will remain disciplined our thoughts on this decision. Also in Brazil, we have spotted 1 tumor exploration well in the MSA site where oil was found. The preliminary results are encouraging, but further analysis and evaluation is needed. In Mozambique, Area 4 Partners submitted to the government the plan of development for the 1st phase of the Rovuma LNG project, which will start developing the large number of regulatory. This first phase PoD comprises 2 LNG trains, each with 7.6% capacity. This is an important milestone for Moserlikon project, and we are targeting FID for next year and first LNG for 2024. In relation to the Coral South FLNG project execution, we are observing that the project is proceeding according to plan, and we expect to have the 1st steel cap for the whole during the second half of this year. The Mozambique projects are key to Gulf strategy, allowing us to have equity LNG as well as progressing towards a lower carbon portfolio mix. As for the downstream, and as previously mentioned, we have a feasible solution to supply IMO compliant products by 2010. We are already producing some bunkering batches according to future specification, which are being tested in a real environment. On the gas business, we established a long term agreement to access 1 MTPA of LNG to be supplied from the United States. This is part of our well slagged gas sourcing strategy to secure a balanced and competitive long term gas sourcing portfolio. So to conclude, our strong focus on executing highly competitive and fast growing projects, together with our disciplined capital allocation, makes us confident with the targets we have committed to. The current macro environment is healthy, and therefore, we are adjusting upwards our short term guidance. However, and more importantly, our long term investment case is becoming more and more robust and derisk it. I will now pass the floor to Filipe. Filipe? Thank you, Felix. Now I'll go straight to Slide 10 and on some of the items which drove our P and L. EBITDA was P and P EBITDA was significantly up year on year to 411,000,000 dollars This is supported by increasing production and oil prices, and this despite the weaker fallow when we compare with last year. We have about €40,000,000 in positive under the term effects, I. E, in Q1, we were accruing volumes, which we ended up selling at a higher price during Q2. The net costs were also down in E and P, mainly driven by higher production dilution. We have past cost adjustments in Brazil as well. And we also have a conversion effect from the weaker Brazil in the field. On Refining and Marketing, EBITDA was BRL 174,000,000. That's down year on year and impacted by about $50,000,000 in a swing in time lag. This is given our marketing price formulas. And exchange rates effects with refining cargoes. This part effects from the rapid increase in Brent prices and the dollar in materials. Yet on a quarter on quarter basis, refinement EBITDA was supported by better realized refined margin and the high availability of the units. If you recall, we had maintenance in the hydrocrackers in Q1. Gas and Power EBITDA decreased $11,000,000 that's year on year to $34,000,000 This is the impacted by the expected lower contribution from LNG20. Not really much else what's highlighting here. Below the line, I would highlight the positive strength in financial results, mostly driven by a positive mark to market in the farming hedges. Net interest also includes year on year, and this is driven by lower debt and lower cost of debt. Net income RCA was BRL 251,000,000 in the quarter, whilst under IFRS, it was BRL330,000,000 and this is helped by a positive inventory effect of BRL 68,000,000 dollars plus $11,000,000 in nonrecurring assets. On Slide 11, we have comps cash flow generation during the first half of 'eighteen. Cash flow from operations accounted to 849,000,000. Again, this is 2 quarters. And this is net of about 200,000,000 in working capital goods, which was mostly commodity price induced. Overall, cash conversion was quite healthy this semester. CapEx so far this year amounted to 368,000,000 the main developments being Glynis 11 and Block 32. This quarter's exploration CapEx also includes the $70,000,000 or so payments for the acquisition of the first 3% stake in BMS-eight, which we announced back in October last year. Our free cash flow during the first half reached EUR 427,000,000 or EUR175,000,000 post dividends. The updated guidance we are providing on Slide 12 derives mainly from higher rent price assumptions. In that case, full year EBITDA guidance is over €2,100,000,000 with every €5 move in Brent translating into around 100 and 50,000,000 in EBITDA. We're keeping our CapEx guidance unchanged at EUR 1,000,000,000 to EUR 1,100,000,000 including the about €150,000,000 in signature bonuses for our lease and acquisitions in Block 799 in Trampos plus the irapuru asset in Santos. These should be payable later this year, whilst the payments for the additional 3% stake in BMS-eight likely to take place only next year. And I will stop here and we're happy to take your questions. Thank you. The first question comes from the line of Oswald Clint calling from Bernstein. Please go ahead. Good morning. Thank you very much. Yes, the first question just on Brazil. And obviously, you said you've been successful in the 2 most recent license lines and adding more Brazilian acreage and resource. I just want to get your sense here. And obviously, you kind of flagged that interest last year. So I wanted to know, do you still have appetite for more acreage within Brazil? And if so, are there any more license lines coming up that you could talk about? That's the first question. And then maybe going back to Gas and Power, I'm just curious about your LNG trading underperforming a little bit in the Q2. It looks like an attractive environment for LNG trading in 2Q. Just wondering what happened that could prevent the gap from benefiting from that? Oswald, good morning. Thank you for attending to our call. So in Brazil, we think that we have a strategic handle. We move quite well the resources we are in Brazil for almost 20 years. We have a total research level And we always look to review in a value approach. We think that our strategic handling in terms of knowledge will allow us to focus in the most promising assets. We will continue to do that. But using our capital allocation, we discipline and focus on value. So all we know, we will continue to look into Brazil as we look around the Atlantic Basin. But Brazil, for the time being, we'll continue to offer interesting opportunities to different projects. In what relates to the LNG, what happens, you know, we are glad that a couple of years ago, we have entered in a medium term contract, international contracts that secure some of our trading activities. Those contracts are ending and the arbitrage alternatives in the markets are insufficient to continue to have those to capture those values. So what we have done is converting our international LNG trading in the period to Extrada hub network, which brands have lower unitary margins, and that's what we are observing. So we will continue to be attentive to opportunistic. And going forward to the opening of the demand in the market That will bring the additional opportunities to the market. Thank you. The next question comes from the line of Mehdi Enibati calling from Associates General. Please go ahead. Hi, good morning, everyone, and thanks for taking my questions. So I have 2 questions, please. The first one on the upstream. So your average realized price, sale price showed a 10.6 dollars per barrel discount to Brent during the Q2. Whereas, as you know, the discount used to be around $8 per barrel in the last quarter. So I just wanted to know why did you have a higher discount this quarter? How much discount should we expect as well in the following quarters? I also have a question regarding your petrochem OpEx, which was $7.7 per barrel in the second quarter. So you highlighted that you benefited from past cost adjustments. So can you please provide us with the level of those adjustments and if we should consider those as one off? Thank you. Hi, Manny. Thank you for your two questions. I will take the second one. I will like to look to the rest of the year. So in what respects to OpEx in our upstream facilities, we have experienced the ramp up as well as trade unit and therefore the volume dilution has increased. And as I've mentioned to you before, the reference OpEx guidance for you should be around $8 per barrel. So that's, I think, more important your consideration. The one maybe realized points, so this is a mix of oil and gas, Angola and Brazil. Brazil, of course, is the big is the biggest of the balance. And this is without any under lifting over lifting effect. So it gives you a pure delivered to shore price, net of the logistic cost of taking it to shore from the FPSOs in Brazil. And it's pretty much according to plan. Thank you. All right. Thank you very much. The next question comes from the line of bhiraj bhorkhataria calling from RBC. Please go ahead. Hi, thanks for taking my questions. I had a couple, please. First, on Brazil again. Could you just clarify what production contribution you assume in your guidance for the 2 FPSOs starting up later this year? And the second question is for you Carlos. Can you just give a bit of color in Brazil, Petrobras, it seems to be quite challenging with the CEO leaving. I just wanted to get your updated thoughts on what's going on there and any changes to your expectations on progress. Biraj, good morning. So in what relates to production, you should calculate our guidance of 15% to 20%, which will includes all the effects, I mean, the first oil of new unit, the ramping up, the collateral of maintenance activities, so you should consider that we will think that it can stand between 15% 20% compared to last year. The second question, exactly, we have we have saw our colleagues from Penperen from Petrobras leaving the company. I think there has been a movement that surprised us, right, including ourselves. What we can say that we have always worked with Kevin and his team in a fantastic and excellent way. And I think that really where we will continue to do it. Because being the people and the individual is important in the company. I do think that relationship between the company and partners goes beyond that. And the projects, the relevance of the projects at 3 as well are so important that we will continue to work together. Effectively, if you ask what we see in terms of changes in the short term, We are not observing anyone, if any. And we continue to work close, one to each other, not only to push ahead the projects where we are already under development and as well to working how we can extract and optimize value from not for all the ones that are in development as well for those that are still in a pre development phase. So all in all, we continue to work with Petrovaraj in the same terms. Of course, these changes makes part of the cabin life, but we cannot comment in details of anything else. Thank you. The next question comes from the line of Rafael Putaj calling from Bank of America Merrill Lynch. Please go ahead. Yes, good morning. Thank you for taking my questions. First one just on your higher EBITDA guidance. I know that the oil price assumptions driving those you've shared. Could you comment on how the refining margins assumptions have changed between new guidance and the old guidance? Because thinking back to your sensitivity, I think you've guided before a €280,000,000 EBITDA move every $10 rule of thumb. And I guess the increase of $200,000,000 to $300,000,000 is perhaps a bit modest on that basis. And then second question just around IMO and thinking out to 2020, I wondered if you could give us a sense of the timing and duration of any maintenance downtime between now and I guess 2020, if you've given any guidance out to the market on that? Thank you. Good morning, Rafael. Thank you for your questions. So first one, the EBITDA guidance and about the refining margins. So effectively, we are keeping more or less the same range. Now looking at both refining margin and not solving the benchmarks. So we think that we can stand between 2.5percent5.5 percent for year for 2018 year end, which is pretty in line with what we have guide to you in our CMD. In what relates to the IMO and any stoppage that we have after then, we are planning to have a stoppage in our FCC unit, but there is nothing related with IMO for the end of the year. So it will be in the 1st Q where we think that we can have between 4 to 50 days VFCC amendments for a general shutdown. During a period where the gasoline is less demanding. So we have planned to have the lowest effect in our operations. Looking into the IMO specifically, we are already making some batches production and testing in with few clients to guarantee that we will be full compliant by the second half of next year. So we don't anticipate any specific tender runs for that purpose. What we will have is that some of the investments that we are promoting now in increasing our conversion capacity for the dollar to barrel additional margin will be on stream by the end next year or beginning of 2020. And that's the major investment, but we will not conflict with the normal operations because we will anticipate the timings to accommodate those units timely when they will be ready to work. Thank you. Thank you. The next question comes from the line of Thomas Adolff calling from Credit Suisse. Please go ahead. Hello. Two questions for me, please. Just to the firstly, to the point of discipline and the big rounds in Brazil. And we have extensively talked about, for example, the 3rd bit round, how the 3rd bit round was very aggressive, more volumes and value. And when I look at the 4th bit round where you won Uirapur, it looks just as bad as Piroga in terms of government profit oil share. So I'm sure there's something that sparked your interest. Perhaps you can kind of talk around it because at first sight, it looks quite an aggressive bid. Secondly, again on Brazil, and you've mentioned you now have 7 FPSOs producing and producing at plateau, some of which producing for many years, some a bit younger. So I wanted to know how many wells you have drilled on these 7 FPSOs and how many are actually not producing because the reservoir is just behaving better? And what it means in terms of potentially giving us an update again on the plateau guidance? Thank you. Good morning, Thomas. In 2Q, I will take the first question and for the second one. Discipline, it's a word that I reevaluate at that. You might say or one might say that the profit sharing that has been offered in Uyghururu asset is quite aggressive. We cannot disclose these from the fact that it's not the profit sharing that is important. It's looking at the global economic conditions that are offered because this is a production sharing agreement contract, which means that the product sharing agreement, Firstly, those 2 to pay the costs. And we look at the volume wise and the probability of success of this asset in a positive sense. So our geologist team is quite positive in the potential of this asset, and it was the case of our partners in the construction. So therefore, I do think that we have well flexed the best assets that we should offer during the mid month. But of course, we will need additional appraisal to see if the potential will be converted in reality. We will think and we are reducing so and we are positive on that. But the time will give us a will give us reason or not. And you should also see that from the competitive perspective, everyone was playing, everyone was bidding. And the difference between the first offer with the second and the third one, it was really minimum, which is completely different for what happens in the different designs and the different assets. So that, I think, can give all of us what is the difference between these assets and the others. I will pass now to Peter. Thank you very much, Carlos. And actually, I would like to add that within the continent, in the consortium, we actually call it the sweet win. When you win, you see the precious one, because that's the next one. That's the really sweet win. We were very active. When it comes to your question with respect to Quirrell, the situation is that there currently are 92 wells operating in Lula Orejana, 6 jets, which are producers, 40 kilowatt injectors. And we have completed 101 out of the total plant of 163 wells in the current plant, and that's where we are. So we expect that with the development. We have research so that as soon as the business are ready, we can go on and implement ourselves in South Sudan. And it's one of the key reasons why B66 were able to ramp up to potential production in 11 months. So this trend will continue. Thank you. Thank you. The next question comes from the line of Josh Stone calling from Barclays. Please go ahead. Thanks. Hi. Good afternoon. I've got two questions, please, both on the Downstream. First, if I can just follow-up on the IMO preparations you're making. Could you provide some indication of how much of your fuel oil production you expect to be compliant with the IMO standards before 2020? And maybe if you wanted to give some details of how you expect to achieve that? And then second, in marketing, if I heard correctly, you mentioned the €50,000,000 negative impact from the time lag effect. So I guess, did I hear that correctly? And secondly, is that an appropriate sensitivity for us to use? We think the oil price is up around $8 so around for each $10 move would be around €70,000,000 per quarter. Is that the sort of magnitude? Hi, Dror. Good morning. Here are all compliant with IMO. First and foremost important is to understand that it will depend on the market conditions. I mean, we are capable to add fully fuel oil, banking fuel oil compliant, which means that we have only deployed optimizing and maximizing our conversion capacity and using different food rates. But what we will do is look into the economics and searching the best economic alternatives between banking compliance here as well and other fuels that will be with a higher sulfur content. So we will continue to have a flexible mindset, value driven approach instead of being only producing IMO compliance for the global production. In what relates to the time line, what Silek is mentioned is that year on year, the swing between time lag and FX in the first floor affecting more the supply chain and also some market maturities. And the second is lower in our P and L, is EUR 50,000,000. So the time lag year on year was BRL 30, the swing and the FX was BRL 20, also the swing year on year. If you look to the quarter on quarter, the time lag was $20,000,000 Again, the swing between the two quarters, the first and the second one, And the FX was $12,000,000 So I think this is clarifying my question. Thank you. Okay. Very clear. Thank you. The next question comes from the line of John Wrigley calling from UBS. Please go ahead. Thank you. Just two questions. The first is on Brazil. I can see the impact of FX on OpEx and I guess by extension on DD and A as well as you've revalued your historic costs. But Is there a deferred tax impact at all that you need to you recognize? And if so, where is it? Presumably, those are recorded in reals as well. The second question is to do with the cash flow and the balance sheet. As you acknowledge, if cash flow has been very strong, I mean, you've upgraded EBITDA, which, I guess, is a reflection of the higher oil price. But obviously, as you move through the year, you derisked your underlying cash flows as well. And you talked to the 2 FPSO start ups, Colombia, obviously, as well on Friday. So I suppose that kind of begs the question about how you're thinking now about optimal balance sheet structure and when that starts to have an impact on your payout, so dividends and I guess probably at some point consideration of buybacks as well. So given that we are halfway through the year, given that oil prices have exceeded most people's expectations and given that your sort of execution has been pretty much spot on. Can you sort of update on your thinking around some shareholder remuneration as well? Good morning, John. I'll take your second question first. You see that we had good cash conversion this 1st semester. That does not mean that discipline is going to change. We continue to in a very disciplined way to look at potential new assets to reinforce our core portfolio. There are 3 transactions done out over the last few months. So around Carcara, 8 rounds in Brazil, we have Peru, 791 in Campos. That's what you should expect from CapEx to look at where we can add value to our portfolio. So no, this is not the time of year to discuss shareholder versus strategic options. We should expect a continuation of what we have been seeing over the last few quarters and nothing else. On the impacts of Flex and OpEx in Brazil. So we have some Q1 versus Q2 timing allocations and some costs that affected OpEx between the two quarters. We do not have a lot of default taxation left in Brazil. What we do have in Brazil is a mix of just currency impacts. We also have accelerated depreciation, which in the local accounts, which helps on taxation. Thank you. Okay. The next question comes from the line of Matt Loftin calling from JPMorgan. Please go ahead. Good morning all. Thanks for taking the questions. 2 please, if I could. First, just on full year CapEx. Could you just expand on what's created the flexibility to accommodate additional Brazil related licensing round costs into the unchanged budget? Just wondering the extent to which you already allowed for that contingency at the beginning of the year versus having outperformed our capital efficiency through Brazil first half of the year? And then second, just going back to the Downstream and strong performance in Q2, especially the margin premium over benchmark. Do you see scope to continue to exceed the sort of the normalized guidance, which I think you referred to as around 1.5 barrels per barrel previously, particularly if wider light heavy spreads persist because OPEC production rises and you deliver the rest of the dollar a barrel on the conversion projects? I will take the second question and Silke will go over the first one in CapEx. So in the downstream and looking at the refining margin, I would like to clarify that due to this uncertainty and discussions about refining benchmark and approaching the IMO, it became more difficult and difficult to have a precise benchmark looking for it. So that's the reason why we have looked up to our GAAP margin. And the guidance that we are providing to you is precisely related to GAAP's margin. So you should also bear in mind that on top of the range of from $4.5 to $5.5 per barrel of gas margin, you should consider that we still have $0.70, so $0.70 of dollar from the dollar to barrel investment project that we have still to capture. So looking into the future, those $0.17 should be integrated in our gas refining margin. But for the time being, we will spend not losing to the benchmark or the premiums that the margin as it were. So, Roberto will elaborate now on CapEx. Absolutely. When we give you guidance, we have a few irons on the fire all the time. So we give sufficient cushion into our guidance to accommodate neutral, inorganic attractive assets. We also have this year a lower payout and we're slightly more better than expected, which also kept us at a greater cushion versus number 1,000,000. Thank you. The next question comes from the line of Alwyn Thomas calling from Exane BNP Paribas. Please go ahead. Good morning, guys. Firstly, on cash flow for me. It seems to me pre working capital cash flow was higher than the actual EBITDA during the quarter. And I appreciate you mentioned some favorable lifting impacts. But could you perhaps bridge or outline the specific reasons as to that? And just follow-up, were you in an overall underlift position at the end of 2Q? And or perhaps just outline perhaps whether this might be reserved or reversed or what the outlook is going forward for the rest of the year? Good morning, everyone. Cash flow, 3 dividends. There are, as Philippe has mentioned to you, several effects that we have had during the quarter and also from the first half of the year. And the most relevant ones are flights in slide number 1 sorry, 11, where you can find the 2 components that were most influenced the cash flow the free cash flow increase were the first, the working capital management, mainly the inventory of the stocks optimization. And we came from stoppaging the hydrocracker in the 1st Q. And during the 2nd Q, we have consumed some of the products that have been prepared for that stoppage. And therefore, that will be a more straight and tight management of our inventory. We have been expanding a decrease in the valuation of the inventory. And the second one is to the replacement. As you can also see, the difference between the IFRS and the LCO taxes are also contributing for the acquisition. There are the main differences, which you of course, there are other effects, the under risking component rates for it, as I already mentioned to you, but we have also the negative effect has improved the HEX cycle and also the time line. So all in all, those are the most relevant ones that you can find in our free cash flow. Thank you. And I guess, how about for the rest of the year, just on cash flows, if there's anything you're able to say on whether you were in number of position at the end of the year, the second quarter? Yes. For the rest of the year, the year end, we will still have maintenance in our SEC system, as I mentioned to you previously, which means that we will have to make a non stop build to prepare that maintenance in the 4Q. That should be recovered by the end of the year. So do you think that we can be in a similar stable provision as we have been in the first half of the year. Okay. Thank you. The next question comes from the line of Yerry Kaktanesh calling from Deutsche Bank. Please go ahead. Good afternoon, gentlemen. Two questions on downstream, please. First, on the marketing volumes. Your direct sales declined 4% year on year. And at the same time, the market the Iberian market grew 6% for the same period. I'm just wondering what was the reason for the lower volumes. Are these driven mostly by the domestic market decline? Or there was some on the because I understand you're selling to Africa as well reported in the rep clients. So I would really appreciate if you could elaborate on that one. And the second question is on IMO again, which I apologize. But you mentioned that you are testing some products with your clients. And if you could provide us with a little bit more details, what exact products are you testing? Is that some kind of blend of mix of gas oil and heavy fuel oil or rather ultra low sulfur fuel oil would be very helpful. So in relation to the market, the market, so first and for most important is the fact that we have been we have a turnaround in refinery that the volume provided for trading activities were different. We also experienced one of our major clients, Master clients in Iberia also has made a major turnaround in their industrial time system. And therefore, it is the one that has more explained what happened in terms of revenue. In what relates to retail activities, we have more than consolidated our market share. We are still in the market in a stable way, which means that we will be we have been able to benefit from the demand increase in the retail business. From the IMO, it will depend on the market dynamics, and we are prepared for all the movements. We are prepared depending on the spread between street power crudes, we are prepared to and the demand from high sulfur fuel vis a vis marine visor or very low sulfur fuel. Our refining system is truly required to respond to the optimal economic solution. I mean, we can put in our system producing only the very low sulfur fuel oil. We can combine that with diesel. We can use more sours between the sweet sours spread. So effectively, we are programming optimization model to get through and to extract the margin values from the refining operations in what relates to IMO as it is in relation to anything. So there is not a unique question in this respect. But what I can assure to you all is that we will get we will work in the optimal solution. If we have to make an evaluation in terms of the IMO impact in GALP's P and L, I would say that it will be neutral deposit it's going forward. In what respects to the upstream, it will have a positive impact as well as oil. We anticipate that the spread between sweet and sour crudes will increase. And being out of sweet producer, we will get far and we will catch her that. Thank you. Thank you very much, Panjim. The next question comes from the line of Jason Kenney calling from Santander. Please go ahead. Hi there, Carlos, Philippe. It's Jason Stembern there. A usual question for me on the effective tax rate, please. I think the effective tax was 43% in the quarter. I was thinking it might be close to 45%, 46%, particularly with the upstream delivery. So can you give us some insights as to where that might move over the second half of the growth? And secondly, on the refining hedging support in the quarter, how do you see refining hedging moving over the second half of the year? And can you update us on how much of your output is hedged going into 2019 also? And then maybe if I could just sneak a third one in. Is there a pre drill estimate on Granzuma that you could share with us, risk resource estimate as you've got that? Jason, good morning. So we have to let them in Tumor for another call in another place. I'm sure that everyone is anxious to get more information that gives us a good index on that we need time to run a lot of them to better trade. And then in what relates to refining engines, so our strategy is to stripping things to the refining margins. So we have implemented a couple of years strategy that turns out to have between 20% or 40% of our throughput volumes hedged. For 2018, so year end, we will have approximately 30%. So it's around 30,000,000 barrels that we have secured at a benchmark refining margin as it was considered in the past at $3,100,000 per barrel. I will let to solicit the FX issue. Good morning, Jason. No changes in guidance from our side. We have assumed you raised a 40% cash tax, 50% P and L tax, at least into the early 2020s, then it should converge to 50s. So we have timing differences, especially when you have in this environment when Brent goes up relatively quickly, we pay our taxes in Brazil the quarter after. So on the cash flow trial, T and L in Texas. And as I mentioned before, we also have accelerated depreciation, which is helpful. Now do bear in mind that in our P and L and cash flow statements, you have this associates line, which is not relevant for us. We have deconsolidated GTMD, we have pipelines, we have assets where you show on the Q and A on the cash flow statement, you have post tax numbers. So you're not taxed again on the associates line. The final question comes from the line of Philippe Rosa calling from Haitong Bank. Please go ahead. Hi, good morning everyone. So 2 for me as well. The first one relates to the FPSO number 3 at Kaduna. We have seen in 2017 a capacity utilization not much above 80% in the first half '18. Again, the capacity utilization has been around 82%. I believe this is partly driven by the fact that the gas processing capacity has been reached already. So I would like to understand whether this is the case or if there is any other explanation. And more importantly, what should be the guidance for the capacity utilization at this specific FPSO at Ilucema? And related with this, the capacity utilization of the second FPSO at Iracema is also coming down. It's still higher, but it's coming down as well. So whether any issue regarding the gas and oil content here in this mix in these FPSOs at Eurexima? That's the first question. And the second question relates to the refining cash cost in Q2, okay, if you exclude the impact from hedging, we have had the same unit cost in dollars that we have in Q2 despite a much higher capacity utilization. Could you just provide an explanation why this has happened because the cost of your bags for refining has been much higher in this quarter than in Q1? Thank you very much. I will take the second question and Thore will go over to the first one. So the cash cost in our refining thesis. One should bear in mind that during the first half and particularly the first Q, we have been executing a turnaround. And therefore, we have another effect. First, the costs have increased for that purpose, for that reason. The second one is the throughputs has decreased due to the fact that the hydrocracker has been under management program. So those two effects combined lends or stands at the reason why we have on a unitary basis are higher cost. So I will now pass to Thiago. Thank you very much, Philippe, for your question. I think number 1, I would like to highlight the current average the availability of both to Lucerne and FASB is between 85% 90%. This is in line with our expectations and it's a flexible performance. That's number 1. Number 2, we are and that is also going to be that is baked into our production guidance by the way that we have given you for this year. Number 2, it has all to do with prudent reservoir management. We need to think longer term so that we are optimizing the upstream recovery of the reservoir. And that's why it is from a reservoir management point of view where we look into what is the optimal max balance in the reservoir so important. It has not to do anything with gas injection. This is all to do with the mass balance in the reservoir and the balance between the oil we've had in and the water we've been into the resource. So it's the totality of mass balance that is the issue. And we continue to look for what is the optimal level. My expectation is that we do not see lower dentists. And that's what I really would love to see on this webcast. Thank you. Thank you very much. Which we hope has been useful to update you on our strategy, execution and Q2 highlights. As always, you please contact our IR team for further clarifications. We wish you all a great summer, and team is looking forward to seeing you soon after. Thank you.