Good morning, ladies and gentlemen. Please welcome to Galp's second 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, welcome to our second quarter's 2018 results conference call. Joining me today is Carlos, who will start with a quick update on our operations during the quarter and our strategy execution achieved so far. We will then go through the results. At the end of the presentation, Thore will join us, 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 including 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, 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 Q2, the EBITDA reached EUR 628 million, 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 EUR 604 million, after dividends, the free cash flow was EUR 146 million. The micro context played an important role on these results, it is also important to highlight the operational performance of our activities and the execution progress of our key projects. Considering where we are here today and our revision of the market conditions for the second half of the year, we now expect 2018 EBITDA to be over EUR 2.1 billion.
As for CapEx, we are keeping our guidance of one to 1.1, but now also considering the Brazilian bid rounds payment on Campos Basin 791 block and also pre-operating. Actually, it will be a re-guidance on the CapEx. I will now briefly go over the performance of our divisions, starting with upstream on slide six of our presentation. The working interest production increased Q1Q, it was supported by the ongoing development on Lula and Iracema, mainly driven by the FPSO number 7 in Lula South, which has reached the normal production plateau in April. We have now all the seven units running at plateau level, that surpassed the 100,000 barrels a day as a mark in Brazil. We will bring online two additional units in Lula during this year, which will complete the first stage of development of Lula and Iracema.
The FPSO to develop the Lula North area has arrived to the Rio de Janeiro Bay from China earlier this month. There are still some works to do and the usual regulatory procedures before the unit is placed on its final location. As for the unit to be developing the Lula Extreme 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 Lula North one. Moving now to Angola. The first FPSO in Cabinda has started production this last Friday, and it is an important milestone for this project. I remind you that the development plan for Cabinda comprises two FPSO units, which should more than offset our production decline from our legacy assets currently producing in Block 14.
All in all, we remain confident that we will deliver on our 2018 production guidance with full-year average production 15%-20% above last year. Moving to the downstream on slide seven. Refining had a good quarter with high utilization rates and a positive performance. Galp's realized refining margin was $6.1 per barrel. We captured the strong middle distillate cracks during the quarter, as well as the slightly lowering gasoline cracks when comparing with the last quarter. Exports to U.S. also contributed positively with a supportive RBOB and ARA 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, as you know, we are working to increase the efficiency and the conversion capacity of our refining system, implementing projects to capture an extra U.S. dollar per barrel. There is already €0.40 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 formulas, lagging from a rapid increase in commodity prices. On the gas and power, we had volume sold to industrial clients higher than in the past two, especially in Iberia. 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. Let me take the opportunity to highlight some of our recent key strategic developments, which will enhance our portfolio competitiveness.
I'm on slide number eight. After acquiring a stake in Block 791 in Campos Basin during the first Q, this last quarter, we reached an agreement to increase our exposure to the pre-salt with an additional 3% in BM-S-8. We will therefore have a fully aligned interest of 20% in both Carcará and North of Carcará alongside Equinor and Exxon, each one with 40%. Additionally, in the latest Brazilian bid round held in June, we acquired a 14% interest in Uirapuru, and also alongside top-tier partners. Petrobras, we liked as an operator, and also with Equinor and Exxon. The interest for these assets was very high, and we are happy with the outcome of this licensing round. We have been very selective in what regards which assets to bid for, and I can assure you that we will remain disciplined with our portfolio decisions.
In Brazil, we have spotted one Guanxuma exploration well in BM-S-8, 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 first phase of the Rovuma LNG project, which will start developing the large Mamba reservoir. This first phase POD comprises 2 LNG trains, each with 7.6 MTPA capacity. This is an important milestone for Mozambique and project. 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. We expect to have the first steel cut for the whole during the second half of this year.
The Mozambique projects are key to Galp's strategy, allowing us to have equity LNG as well as progressing towards a lower carbon portfolio mix. As for the downstream, as previously mentioned, we have a feasible solution to supply IMO-compliant products by 2030. We are already producing some bunkering batches according to future specifications, which are being tested in a real environment. On the gas business, we have established a long-term agreement to access 1 MTPA of LNG to be supplied from the U.S. This is part of our well-selected gas sourcing strategy to secure a balanced and competitive long-term gas sourcing portfolio. 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 market environment is healthy. Therefore, we are adjusting upwards our short-term guidance.
However, more importantly, our long-term investment case is becoming more and more robust and de-risked. I will now pass the floor to Filipe.
Thank you, Carlos. Going straight to slide 10 and on some of the items which drove our P&L. E&P EBITDA was significantly up year-on-year to EUR 411 million. This is supported by increasing production and oil prices. This despite the weaker dollar when we compare with last year. We have about EUR 40 million in positive under-lifting effects, i.e., in Q1, we were accruing volumes, which we ended up selling at a higher price during Q2. Unit costs were also down in E&P, mainly driven by higher production dilution. We had past cost adjustments in Brazil as well. We also have a conversion effect from the weaker Brazilian real. On refining and marketing, the EBITDA was EUR 174 million. That's down year-on-year and impacted by about EUR 50 million in a swing in timeline.
This is given our marketing price formulas and exchange rates affects the refining covenants. These are effects from the rapid increase in Brent prices and the dollar in materials. Yet, on a quarter-over-quarter basis, refining EBITDA was supported by better realized refining margins and the high availability of units. If you recall, we had maintenance in the hydrocrackers in Q1. Gas and power EBITDA decreased EUR 11 million. That's year-over-year to EUR 34 million. This is impacted by the expected lower contribution from LNG trade. Not really much else worth highlighting here. Below the line, I would highlight the positive swing in financial results, mostly driven by a positive mark-to-market in refining hedges. Net interest also improved year-over-year, this is driven by lower debt and a lower cost of debt.
Net income RCA was EUR 251 million in the quarter, whilst under IFRS it was EUR 330 million, this is helped by a positive inventory effect of EUR 68 million, plus EUR 11 million in non-recurring items. On slide 11, we have Galp's cash flow generation during the first half of 2018. Cash flow from operations amounted to EUR 849 million. Again, this is two quarters, this is net of about EUR 200 million in working capital builds, which was mostly commodity price induced. Overall cash conversion was quite healthy this semester. CapEx so far this year amounted to EUR 368 million, the main developments being BM-S-11 and Block 32. This quarter's exploration CapEx also includes the EUR 70 million or so payment for the acquisition of the first 3% stake in BM-S-8, which we announced back in October last year. Our free cash flow during the first half reached EUR 427 million or EUR 175 million post dividends.
The updated guidance we are providing on slide 12 derives mainly from higher Brent price assumptions. In that case, full-year EBITDA guidance is over EUR 2.1 billion with every $5 move in Brent translating into around EUR 150 million in EBITDA. We're keeping our CapEx guidance unchanged at EUR 1 billion-EUR 1.1 billion, including the about EUR 150 million in signature bonuses for our recent acquisitions in Block C-M-791 in Campos, plus the lead equity asset in Santos. These should be payable later this year, whilst the payments for the additional 3% stake in BM-S-8 likely to take place only next year. I will stop here and be happy to take your questions. Thank you.
If you would like to ask a question via the phone line, please press *1 on your telephone keypad and ensure that your telephone line is unmuted locally. You'll then be advised when to ask your question. As a reminder, you will be permitted to ask two questions only. The first question comes from the line of Oswald Clint calling from Bernstein. Please go ahead.
Good morning. Thank you very much. The first question just on Brazil, obviously you said you've been successful in the two most recent license rounds and adding more Brazilian acreage and resource. I just want to get your sense here, obviously you kind of flagged that interest last year. I wanted to know, do you still have appetite for more acreage within Brazil? If so, are there any more license rounds coming up that you could talk about? That's the first question. Then maybe going back to gas and power. I'm just curious about your LNG trading underperforming a little bit in the second quarter. It looks like an attractive environment for LNG trading in 2Q. I just wonder what happened that kind of prevented Galp from benefiting from that. Thank you.
Hi, Oswald. Good morning. Thank you for attending to our call.
In Brazil, effectively, we think that we have a strategic angle, we know quite well the resources. We are in Brazil for almost 20 years. We have a technical research as well, we always look to Brazil in a value approach. We think that our strategic angle in terms of knowledge will allow us to focus on the most promising assets. We will continue to do that. Using our capital allocation, we discipline and focus on value. All we know, we will continue to look into Brazil as we look around the Atlantic basin. Brazil, for the time being, will continue to offer interesting opportunities to different parties. In what relates to the LNG, what happened, you know quite well that a couple of years ago, we have entered in a medium-term contract, international contract that secure some of our trading activities.
Those contracts are ending, the arbitrage alternatives in the market are insufficient to continue to capture those values. What we have done is converting our international LNG trading activities to a hub network, which gradually lower unitary margins, that's what you are observing. We will continue to be attentive to opportunities going forward to the opening of the demand in the market. That could bring additional opportunities to the market. Thank you.
Super. Thank you.
The next question comes from the line of Mehdi Ennebati, calling from Societe Generale. Please go ahead.
Hi. Good morning, all, and thanks for taking my questions. I have two questions, please. The first one on the upstream. Your average realized price, sell price, shows a $10.6 per barrel discount to Brent during the second quarter. As you know, the discount used to be around $8 per barrel the last quarter. 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 upstream OpEx, which was $7.7 per barrel in the second quarter. You highlighted that you benefited from past cost adjustments. Can you please provide us with the level of those adjustments, and if we should consider those as one-off? Thank you.
Hi, Mehdi. Thank you for your two questions. I will take the second one. I will ask Filipe Silva to address the realized price. In what respects to OpEx in our upstream activities, we have experienced the ramp-up of the last unit, and therefore, the drilling dilution has increased. As I've mentioned to you before, the reference OpEx guidance for you should be around $8 per barrel. That's, I think, more important for your consideration. Filipe Silva.
Mehdi, the realized price. This is a mix of oil and gas, Angola and Brazil. Brazil, of course, is the biggest of the volumes, and this is without any underlifting, overlifting factor. It gives you a pure delivered to shore price, net of the logistic cost of taking it to shore from the FPSOs in Brazil. It is pretty much according to plan. Thank you.
All right. Thank you very much.
The next question comes from the line of Biraj Borkhataria, 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 two FPSOs starting up later this year? The second question for you, Carlos, could you just give a bit of color? In Brazil, with Petrobras, it seems to be quite challenging with the CEO leaving. I just wanted to get your updated thoughts on what is going on there and any changes to your expectations on progress. Thanks.
Hi, Biraj. Good morning. In what relates to production, you should count with our guidance of 15%-20%, which includes all the effects. I mean, the first oil of new units, the ramping up, the plateau level, maintenance activities. You should consider that we will think that we can spend between 15% and 20% comparing last year. The second question. Exactly, we have saw our colleagues from Petrobras leaving the company. I think there's been a movement that surprised everyone, including ourselves. What we can say is that we have always worked with Pedro and his team in a fantastic and excellent way, and I think that we will continue to do so. Being the people and the individuals important in the company, I would think that relationship between the company and partners goes beyond that.
The relevance of the projects that we have together are so important that we will continue to work together. Effectively, if you ask us what we see in terms of changes in the short term, we are not observing anyone, if any. We continue to work closely, 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 only the ones that are under development, as well for those that are still in a pre-development phase. All in all, we continue to work with Petrobras in the same terms. Of course, these changes make part of the company lives. We cannot comment in details of anything else. Thank you.
That's great. Thanks, Carlos.
The next question comes from the line of Rafal Gutaj 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 note that the oil price assumptions driving this, you've shared. Could you comment on how the refining margins assumptions have changed between the new guidance and the old guidance? Thinking back to your sensitivity, I think you'd guided before a $280 million EBITDA move for every $10 rule of thumb, and I guess the increase of $200 million to $300 million is perhaps a bit modest on that basis. Second question, just around IMO and thinking out to 2020. I'd 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, Raphael. Thank you for your questions. First one, the EBITDA guidance and about the refining margins. Effectively, we are keeping more or less the same range. Now looking at that refining margin, not solving only the benchmark. We think that we can spend between $2.5 and $5.5 for 2018 year-end, which is pretty in line with what we have guided to you in our CMD. In what relates to the IMO and any stoppage that we have after that, we are planning to have a stoppage in our FCC unit, but there is nothing related with IMO for the end year. It will be in the first Q1, where we think that we can have between 14 and 15 days the FCC in maintenance for a general shutdown. During the period where gasoline is less demanding.
We have planned to have the lowest effect in our operations. Looking into the IMO specifically, we are already making some batches production under testing and with a few clients to guarantee that we will be fully compliant by the second half of next year. We don't anticipate any specific turnaround for that purpose. What will happen is that some of the investments that we are promoting in increasing our conversion capacity for the barrel to barrel additional margin will be on stream by the end next year or beginning of 2020. That's the major investment that 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 firstly, to the point of discipline and the bid rounds in Brazil. We have extensively talked about, for example, the third bid round, how the third bid round was very aggressive, more volume than value. When I look at the fourth bid round where you won Uirapuru, it looks just as bad as Peroba in terms of Government profit oil share. I'm sure there's something that sparked your interest, and perhaps you can talk around it, because at first sight, it looks quite an aggressive bid. Secondly, again, on Brazil, you've mentioned you now have seven FPSOs producing at plateau, some of which producing for many years, some a bit younger.
I wanted to know how many wells you have drilled on these seven FPSOs, and how many are actually not producing because the reservoir is just behaving better. What it means in terms of potentially giving us an update again on the plateau guidance. Thank you.
Good morning, Thomas, and thank you. I will take the first question, Tor will answer the second one. Discipline. That's a word that I reevaluate a lot. One might say that the profit-sharing that has been offered in 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 production sharing agreement firstly goes to pay the costs. We look at the volume wise and the probability of success of this asset in a positive sense. Our geologist team is quite positive in the potential of this asset, and it was the case of our partners in the consortium.
Therefore, I do think that we have red flagged the best assets that we should offer, during the bid rounds. That, of course, we will need additional appraisal to see if the potential will be converted in reality. We do think, and we are positive on that the final will give us reason enough. We should also see that from the competitive front of view, 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 from what happens in the different bid rounds and the different assets. That, I think, can give all of us what is the difference between this asset and the others. I will pass now to Thore.
Thank you very much, Carlos. Actually, I would like to add that within the consortium, we actually called it the sweet win. When you win with three potential clients together, it's a next one that will be sweet. We are very happy with it. When it comes to your question with respect to the wells, the situation is that there currently are 92 wells operating in which are producers, 42 of which are injectors. We have completed 101 out of the total plan of 163 wells in the current plan, and that's where we are. We are quite happy with the development. We have reserved so that as soon as the unit is ready, we can go on with another 30 as well. It's one of the key reasons why P-66 were able to ramp up to the total production within 11 months.
This trend will continue. Thank you.
Thank you.
The next question comes from the line of Joshua Stone calling from Barclays. Please go ahead.
Thanks. Hi, good afternoon. I've got two questions please, both from 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? Maybe if you're willing to give some details of how you expect to achieve that. Second, in marketing, if I heard correctly, you mentioned a EUR 50 million negative impact from the time lag effect. I guess firstly, did I hear that correctly? 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 EUR 70 million per quarter. Is that the sort of magnitude? Thank you.
Hi, Josh. Good morning. Fuel oil compliance with IMO. First and foremost important is to understand that it will depend on the market conditions. We are capable to have fully banking fuel oil compliant, which means that we are only to play optimizing and maximizing our conversion capacity and using different fuels. What we will do is look into the economics and searching the best economic alternatives between banking compliant fuel oil and other fuel that would be with higher sulfur content. 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 lag, what Filipe has mentioned is that year-on-year, the swing between time lag and FX in the first quarter affecting more on the supply chain and also some marketing activities.
The second is globally in our P&L is EUR 60 million. The time lag year-on-year was 30, the swing, and the FX was 20, also the swing year-on-year. If you look to the quarter-on-quarter, the time lag was 20. Again, the swing between the two quarters, the first and the second one, and the FX was EUR 12 million. I think this is qualifying your question. Thank you.
Okay. Very clear. Thank you.
The next question comes from the line of Jon Rigby 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&A as well as you've revalued your historic costs. Is there a tax impact at all that you recognize? And if so, where is it? Because presumably those are recorded in BRL as well. The second question is to do with the cash flow and the balance sheet. As you acknowledge, cash flow has been very strong. You've upgraded EBITDA, which I guess is a reflection of the higher oil price. Obviously, as you've moved through the year, you've de-risked your underlying cash flows as well, and you've talked to the two FPSO startups, Kaombo, obviously, as well on Friday.
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 dividend and I guess probably at some point, consideration of buybacks as well. Given that we are halfway through the year, given that oil prices have exceeded most people's expectations, and given that your execution has been pretty much spot on, can you update on your thinking around shareholder remuneration as well? Thanks.
Good morning, Jon. I'll take your second question first. You see that we had good cash conversion this first 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 three transactions going on over the last few months. Around Carcará, three rounds in Brazil, Iracema, 791 in Campos. That's what you should expect from Galp. No, this is not the time of year to discuss shareholder versus strategic options. You should expect a continuation of what you have been seeing over the last few quarters and nothing else. On the impacts of tax and OpEx in Brazil.
We have some Q1 versus Q2 timing allocations and some costs that affect the OpEx between the two quarters. We do not have a lot of deferred taxation left in Brazil. What we do have in Brazil is a mix of less currency impacts. We also have accelerated depreciation in the local accounts, which helps on taxation. Thank you.
Okay.
The next question comes from the line of Matthew Lofting calling from J.P. Morgan. Please go ahead.
Morning, all. Thanks for taking the questions. Two, 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 on capital efficiency through Brazil first half of the year. 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 per barrel previously, particularly if wider, like heavy spreads persist as OPEC production rises, and you deliver the rest of the $1 a barrel on the conversion project? Thanks.
Hi, Matt. Good morning. I will take the second question and Salvatore will go over the first one in CapEx. In the downstream, I am 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 becomes more difficult to have a precise benchmark looking forward. That is the reason why we are looking to our Galp's margin, and the guidance that we are providing to you is precisely related with Galp's margin. You should also bear in mind that on top of the range of some $4.5-$5.5 per barrel of Galp's margin, you should consider that we still have $0.70 from the dollar-per-barrel investment project that we have still to capture.
Looking into the future, those $0.70 should be integrated in our Galp's refining margin. For the time being, we will spend not looking to the benchmark or the premiums that the margin over there. Later, we will elaborate more on topic.
Absolutely. When we give you guidance, we have a few irons on the fire all the time. We build sufficient cushion into our guidance to accommodate little economic attractive assets. We also have this year a lower BRL and a slightly lower dollar than expected, which also helped us have a bit of a cushion. It is normal enough. Thank you.
Very clear. Thanks, gents. Appreciate it.
The next question comes from the line of Alwyn Thomas calling from Exane BNP Paribas. Please go ahead.
Good morning, guys. First thing on cash flow for me. It seems to me pre-working capital cash flow was higher than the actual EBITDA during the quarter. I appreciate you mentioned some overall lifting impact, could you perhaps bridge or outline the specific reasons as to that? Just follow up, were you in an overall underlift position at the end of 2Q? Perhaps just outline whether this might be reversed or what the outlook is going forward for the rest of the year. Thank you.
Good morning, Alwyn. Cash flow, three reasons. There are, as Filipe has mentioned to you, several effects that we have had during the quarter and also from the first half of the year. The most relevant ones are flagged in slide number one, sorry, 11, where you can find the two components that were most influenced, the free cash flow increase, were the first, the working capital management, mainly the inventory, the stocks optimization. We came from a stoppage in the hydrocracker in the first Q. During the second Q, we have consumed some of the products that have been prepared for that stoppage. Therefore, that, together with a more strict and tight management of our inventory, we have had a decrease in the valuation of the inventory. The second one has to do with taxes.
As you can also see, the difference between the IFRS and the RCA taxes are also contributing for that difference. They are the main differences we feel. Of course, there are other effects, the underlifting from government, actually, as I already mentioned to you. We have also the negative effect of the export and also the timeline. All in all, those are the most relevant ones that you can find in our free cash flow. Thank you.
I guess, Alwyn, for the rest of the year, just on cash flows, if there's anything you're able to say on whether you were in underlift position at the end of the second quarter?
For the rest of the year, the year-end, we will still have a maintenance in our FCC system, as I mentioned to you previously, which means that we will have to make a stock build to prepare that maintenance in the third Q. That should be recovered by the end of the year. We think that we can be in a similar stable position as we have been in the first half of the year. Thank you.
Okay, thank you.
The next question comes from the line of Yuriy Kukhtanych calling from Deutsche Bank. Please go ahead.
Yes. Good afternoon, gentlemen. Two questions on downstream, please. First on the marketing volumes. Your direct sales declined 4% year-over-year. At the same time, 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 something, because I understand you're selling to Africa as well, reported indirect clients. I would really appreciate if you could elaborate on that one. The second question is on IMO again, for which I apologize. You mentioned that you are testing some products with your clients. If you could provide us with a little bit more details, what exact products are you testing? Is that some kind of blend or mix of gas oil and heavy fuel oil or rather ultra-low sulfur fuel oil?
Would be very helpful. Thank you.
Good morning, Yuri, and thank you for your question. In relation to the market. First, most important, is the fact that we had a turnaround in Sines Refinery that showed the volume delivered 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 plant system, and therefore it is the one that has more explained what happened in terms of volume. In what relates to retail activities, we have more than consolidated our market share. We are selling the market in a steady rate, which means that 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.
Depending on the spread between sweet, sour crudes, we are prepared to, under the demand from high sulfur fuel oil, vis-a-vis the marine diesel or the very low sulfur fuel oil. Our refining system is fully prepared to respond to the optimal economic solution. We can put our system producing only the very low sulfur fuel oil. We can combine that with diesel. We can use more sour depending on the sweet sour spread. Effectively, we are keeping all the optionality open in order to guarantee that we will use our linear programming optimization model to get and to extract the maximum value from the refining operations, in what relates to IMO as it is in relation to anything. There is not a unique question in this respect.
What I can assure to you all is that we will get and we will work in the optimal solution. If we have to make an evaluation in terms of the IMO impact in Galp's P&L, I would say that it will be neutral to positive going forward. In what respects to the upstream, it will have a positive impact as well, as far as we anticipate that the spread between sweet and sour crudes will increase. Being Galp, the sweet producer, we will get that and we will capture that value. Thank you.
Thank you very much. Thank you.
The next question comes from the line of Jason Kenney calling from Santander. Please go ahead.
Hi there, Carlos, Filipe. It's Jason from Santander. A usual question from me on the effective tax rate, please. I think the effective tax was 43% in the quarter. I was thinking it might be closer to 45, 46, particularly with the upstream delivery. If you can give us some insights as to where that might move over the second half, that'd be great. Secondly, on the refining hedging support in the quarter, how do you see refining hedging moving over the second half of the year? Can you update us on how much of your output is hedged going into 2019 also? Maybe if I could just sneak a third one in. Is there a pre-drill estimate on Guanxuma that you could share with us? Risked resource estimate, if you've got that. Thanks.
Hi, Jason. Good morning. We have to let Guanxuma for another call and another place. I'm sure that everyone is anxious to obtain more information, but soon. It's a good index on that. We need time to learn a lot and to better trade.
Okay.
In what relates to refining margins, our strategy is to sweeten the refining margin. We have implemented a couple of years. Our strategy that turns out to have between 20% and 30% of our throughput volumes are hedged. For 2018, year-end, we will have approximately 30%. It's around 30 million barrels that we have secured at a benchmark refining margin as it was conceived in the past at $3.1 per barrel. I would like to solicit the first few issues.
Good morning, Jason. No changes in guidance from our side. What we've seen here is the 40% cash tax, 50% P&L tax, at least into the early 2020s, and then it should converge to 50s. 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. On a cash year 12 P&L taxes. As I mentioned before, we also have accelerated depreciation, which is helpful. Now do bear in mind that in our P&L and cash flow statements, you have this associates line, which is quite relevant. We have deconsolidated GGND, we have pipelines, we have assets where you show on the P&L, on the cash flow statement, you have post-tax numbers. You're not taxed again on the associates line.
Thank you.
Okay, thanks.
The final question comes from the line of Filipe Rosa, calling from Haitong Bank. Please go ahead.
Hi, good morning, everyone. Two for me as well. The first one relates to the FPSO number 3 at Iracema. We have seen in 2017 a capacity utilization not much above 80%. In the first half 2018, 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. I would like to understand whether this is the case or if there is any other explanation. More importantly, what should be the guidance for the capacity utilization at this specific FPSO at Iracema? 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. Whether any issue regarding the gas and oil content here in this mix in these FPSOs at Iracema? That's the first question.
The second question relates to the refining cash cost in Q2. If you exclude the impacts from hedging, we have had the same unit cost in dollars then that we have in Q2, despite a much higher capacity utilization. Could you just provide an explanation why this has happened? Because the cost you hedge for refining has been much higher in this quarter than in Q1. Thank you very much.
Hi, Filipe. Good morning. I will take the second question and João will go over the first one. The cash costing in our refining season. 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 a double effect. First, the costs have increased for that purpose, for that reason. The second one is the throughput has decreased due to the fact that the hydrocracker has been under maintenance for a bit. Those two effects combined lends or stands at the reason why we have in unitary basis higher costs. I will now pass to João.
Thank you very much, Filipe, for your question. I think number one, I would like to highlight that on average, the availability of both Iracema FPSOs is between 85%-90%, basically in line with our expectations and successful performance. That's number one. Number two, that is also being taken into our production guidance forward that we have given you for this year. Number two, it has all to do with prudent reservoir management. We need to think longer term so that we are optimizing the optimum recovery of the reservoir. That's why it is from a reservoir management point of view, where we look into what is the optimal mass balance in the reservoir so important. It has not to do anything with gas injection.
It is all to do with the mass balance in the reservoir and the balance between the oil we take in and the water we bring into the reservoir. It's the totality of mass balance that is the issue. We continue to look for what is the optimal level. My expectation is that we will not go lower than this. That's what I really like to see on this webinar. Thank you.
Thank you very much.
Our latest in this session, which we hope has been useful to update you on our strategy, execution, and Q2 highlights. As always, feel free to contact our IR team for further clarifications. We wish you all a great summer, and team is looking forward to see you some after. Thank you.