Good morning, ladies and gentlemen. Please welcome to Galp's first quarter 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 first quarter 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. Filipe will go through the results. At the end of the presentation, we'll 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 statement available at the beginning of our presentation, which we advise you to read. I will now hand over to Carlos. Thank you.
Thank you, Pedro, good afternoon to you all. I believe that today, we should be rather straightforward update considering our recent capital markets day. To start, let me give you a quick overview on what happened during this first quarter. We saw Brent traded as high as $70 per barrel, on the other hand, refining margins were down significantly. On the operational side, we continue to execute our key projects and to manage our activities focused on its value optimization. This as we work on expanding our projects pipeline with new promising assets and solutions aligned with our strategic guidelines that you well know. The cash flow generation from operations in the quarter reached EUR 245 million in spite of a significant investment in working capital, which Filipe will cover later on.
Within this cash flow, you will see that group EBITDA was up 17% year-over-year, mostly supported by the E&P businesses, which benefited from higher oil and natural gas prices and as well from the production growth. Q1Q, our EBITDA was down 4%, following a more challenging refining environment and of course, a weaker U.S. dollar. Regarding the downstream businesses, besides the lower benchmark margins, I highlight the planned maintenance in our Sines hydrocracker, which was executed safely. As of course, it limited the quarter's throughput and the conversion capacity. Overall, Galp generated positive free cash flow in a tough quarter, even though helped by the lower realized CapEx level in the period. You may have seen that we also continue to build our portfolio in Brazil, with Galp participating in the 15 concession bidding rounds and acquiring one exploration block in Campos Basin.
We do believe this block holds pre-salt potential. This reflects our commitment to maintain a resilient portfolio and to expand our presence in core areas through strong partnerships. Our solid balance sheet enables us to take advantage of selected opportunities that might arise in the market, but always, I underline always following a financial discipline and a value over volume strategy. Let me just briefly cover the performance of our division, starting by the E&P on slide six of our presentation. Production increased Q1Q supported by the continuous development of Lula and Iracema in Brazil. This came mostly from the FPSO number 7, placed in Lula South, which had its sixth producer connecting during the period. The unit achieved its oil production plateau level just recently.
This just 11 months after its first oil and shows once again the tremendous job the teams are doing to execute and de-risk this world-class project. I also highlight that the gas exports will only start once the unit is connected to the existing gas network system, which is expected for later this quarter. Today, we have all the units in Brazil running at plateau. As you know, we expect two new units to come online in Brazil during the second half of the year. In Iara, we started the EWT in Sururu Southwest. This test will provide useful information to optimize the complete drainage plan for this reservoir. Meanwhile, in what respects to Carcará, we continue to work with our partners on the appraisal campaign.
We have just concluded the DST in Carcará Northwest, which will enable us to better understand the quality of the reservoir and its potential productivity. We are currently assessing that data. Moving to Angola on slide seven. In Block 32, the FPSO to be allocated to Kaombo Norte arrived from Singapore and is already on its final location. Drilling campaign is progressing according to plan, with 26 out of 59 wells already drilled. We should start production during the second half of this year. Let's move now to the downstream on slide eight. Refining had a challenging quarter, apart from the scheduled maintenance that we have anticipated in our Sines refinery hydrocracker. We also saw a significant decrease in refining margins, which was well-flagged on the European benchmark, mainly due to the sharp increase in oil prices and the strong decline of gasoline and fuel oil cracks.
Our benchmark was down 47% Q1Q, with Galp's being able to get an additional $1.5 per barrel as a spread over this benchmark, despite the hydrocracker maintenance, and positively also impacted by the hedged volumes during the period. All in all, our implicit refining margin was down only 22% Q1Q in dollar terms. As you know, we are working to increase the efficiency and conversion capabilities of our refining system, implementing projects to capture an additional $1 per barrel. There is already a part of this value on the spread achieved during this quarter. Finally, margins have slightly recovered earlier this month, but are again stressed by lower fuel oil cracks. You should bear in mind that we have around 25% of our 2018 refining throughput that is hedged at $3.8 per barrel.
As for the marketing activity, despite the seasonally lower volumes and some impact from having lower refinery throughputs, performance benefits from the Iberian economic momentum and the consolidation that we gave in our market share. In what respects to the Galp Gas and Power, we increased our sales to direct clients, namely to the industrial segments. On the trading side, LNG continues to be somewhat limited and based on our structured contracts. The gas network trading activities maintained a supportive contribution, benefiting from arbitrage opportunities between European hubs during the quarter, even though the volumes were slightly down Q1 Q, but with better margins. That's it from me. I will now pass to Filipe, that goes in the financials. Thank you.
Thank you, Carlos, and good afternoon. Just a quick overview from me on the Q1 numbers, which should be fairly straightforward. I will start with the P&L on slide 10, where group EBITDA in Q1 was up 17% year-on-year to EUR 455 million. This is driven by much higher Upstream contribution. A slight decrease quarter-on-quarter was driven by refining headwinds and the weaker dollar. E&P EBITDA of EUR 293 million was way up year-on-year. It was flat quarter-on-quarter as the weaker dollar and the slightly higher OPEX offset the higher realized prices. You will have seen that starting this year, we are booking as an expense all exploration, G&A, and G&G costs, so geological and geophysical costs. These are now accounted for under operational costs, so they are no longer capitalized.
This successful efforts method leads to a lower EBITDA and a lower CapEx of the same amount. It also brings forward some cash tax efficiencies. We are showing 2017 numbers restated for ease of comparison. On Refining and Marketing, EBITDA was EUR 122 million. This is down both quarter-on-quarter and year-on-year, and mostly on the lower refining margins, but also impacted by the hydrocracker maintenance and the dollar depreciation. Gas and Power EBITDA was up EUR 14 million year-on-year, reflecting the slightly better European gas prices environment. If you recall, Q1 2017 had been negatively impacted by sourcing restrictions in Algeria. There's a bit of a base effect here as well. Below the line, I would only highlight the EUR 39 million in associates and the higher P&L taxes, mainly as a result of the higher E&P result mix.
RCA net income was EUR 135 million during the period and EUR 130 under IFRS. Non-recurring items were all related to the extraordinary taxes on the energy sector. On slide 11, CapEx was EUR 146 million and mainly allocated to BMS 11 and Block 32 developments. This was a low realization quarter, with the forthcoming quarters expected to catch up. The signature bonus for our recent bid round win in Campos of about $33 million will be payable only later this year. Same for the $17 million or so of the first payment for the acquisition of the 3% stake in BMS-8, which we announced last year. On slide 12, we have cash flow from operations of EUR 245 million. This is already net of EUR 159 million of working capital build.
This is, or was, to a large extent, commodity price induced, but we also had higher inventory levels resulting from the maintenance periods in the refinery and temporary restrictions in the Sines ports at the very end of March. On slide 13, net debt was stable at around EUR 1.9 billion, with the implicit net debt to EBITDA standing at one time. The average debt maturity is currently 2.9 years, with the total cost of debt now under 3%, and this is expected to fall further as we retire older, more expensive debts. We have already refinanced most of the 2018 maturities. As for liquidity, we had around EUR 2.5 billion between cash and undrawn credit lines. This is it from me. We are now happy to take your questions. Thank you.
Ladies and gentlemen, if you would like to ask a question, please press star one on your telephone keypad. If you change your mind and you want to withdraw your question, please press star two. Be reminded that only two questions per person will be allowed. We have the first question coming from the line of Christopher Kuplent from Bank of America. Christopher, you are now unmuted.
Hello. Thank you very much. Just maybe a bit more backdrop question, so shortly after your capital markets day update. As you look into Mozambique, have you got anything new to report in terms of the progress you're making and giving us a little bit of a heads up in terms of FID expected? Thank you.
Thank you, Christopher, for your question. We are having a technical problem. In relation to Mozambique and in what respects to, namely to Mamba. After the ExxonMobil entering the consortium, we are together analyzing how we can optimize the development concept. That's the work that is being done so far. Of course, at the same time, we have parallel teams working on the marketing and also in the project financing. In what respects to the FID, we expect to have the FID next year. Basically, 2018 is a year to mature and to better appraise which are the alternative solutions to have the most profitable and competitive project in the business. Thank you.
Thank you very much. Just a quick follow-up. That means the CapEx this year is going to be replaced incrementally, because if you wait for another year with the FID, I don't expect Mozambique to cost you much in 2019.
In Mozambique, what you should consider, all of us, it's basically that Coral is progressing according to plan, and therefore we will invest in Mamba. In onshore, basically to deepening and to develop the concepts that could be the alternative solution for Mozambique. There's some CapEx that has to be spending, but for the concept development process.
Okay. Thank you.
The next question comes from the line of Oswald Clint from Bernstein. Oswald, you are now unmuted.
Good afternoon, Carlos. Thank you. I wanted to ask a question about the upstream unit OpEx, please. The EUR 9.2 per barrel. It ticked up a little bit in the quarter. Is that simply the startup costs on the Iara EWT or the further declines in Angola? Perhaps talk about that number, what's happening there and your expectations for the rest of the year, please. Also related to Brazil, I think one of your key milestones this year was one of the EOR enhanced recovery initiatives on Lula. We're a third of the way through the year, perhaps you could give us an update on where you are with those initiatives, please. Thank you.
Hi, Oswald. Good afternoon. In respect to the OpEx comparing Q1 to Q1 is slightly the difference. First, we have an additional unit, we are executing the EWT in Sururu, which means that we have additional costs. We have also had, during the period, some constraints on the . Of course, there are also some credits in Brazil that have been considered in the Q4 of 2017, that are not happening in the Q1 of 2018. All in all, and going forward, if you should consider a figure, you should stand around EUR 8 per barrel. In what relates to the other points of the EOR. Galp, of course, has its own and has always autonomous analysis in what relates to research and development and the studies that we are performing.
We are working together with our partners in BMS-11 in order to provide an optimization in what respects to the in-field assessment. It's something that is an ongoing project within the consortium. Thank you, Oswald.
The next question comes from the line of Alwyn Thomas from Exane BNP Paribas. You can go ahead.
Good afternoon, gentlemen. Can I just ask on Petrogal, as you move towards a free cash flow generating position, could you just talk a little bit about how the cash will be redistributed over the next two or three years? Whether that's going to more likely come in the form of dividends, low repayments or used to reinvest in Brazil, whether you keep it in country or expect to. Follow up on that, can I just ask on progress of the exploration drilling at Carcara and the plans for the appraisal and exploration drilling on the North field as well. Thank you.
Good afternoon, Alwyn. Starting from the first question that you have addressed. Basically, if you go back to our CMD presentation, you can see how we intend to redeploy our capital in the coming years. Effectively, most of the CapEx is allocated for, and approximately 60% is committed for the projects that are still undergoing. We do see some room space for expanding our activities for new solutions and also primary renewable energy that we consider between 5% and 15%. Depending on the context and environment and the progress of our operations, we will every year review our dividend policy accordingly that environment. Effectively it's basic where we are today.
Sorry, I meant at Petrogal, just in Brazil, how you allocate.
In Brazil.
Yeah.
In Brazil. Looking into Brazil. Brazil, as you saw during the last, I would say half a year, we have been actively participating in the bid round concessions that are held in Brazil, and we will continue to do that. We have basically two or three options sequentially to adopt. The first one is to continue to search for new DROs or new opportunities in Brazil, which has been the case. Secondly, I used to say we have a long run to go in order to extract more value with incremental projects on the existing assets. We have quite some time to continue to derisk and to show and to prove their endogenous value. We only consider to redistribute and send back to the shareholders some dividends if we will not find additional investment opportunities.
We are very an open-minded way on approaching through Petrogal Brasil to continue to expand our activity. Is that clear for you?
Yes, thank you. Carcara progress?
Let's get to the Carcara. In Carcara, I would say that we can look to the Carcara as an old BMS-8 plus the Carcara North. We are working together in the JV with Statoil in order to continue the de-risking program. We have performed the DST in the Carcara Northwest that has been done in the last three, four months, and that is confirming some of our initial expectations and has been recently concluded. We have also stated to you that in our program, we have the plan to enter in the appraisal of Guanxuma area, which is something that we are now taking in our hands. We expect that in the second half of the year, we might step for the north of the Carcara.
It's something that is being managed in a way to guarantee that we have all the conditions to start that process. All in all, the global appraisal that is being performed in this BMS-8/north of Carcara is a well-established and documented program of appraisal in order to well define the concept development that we will have to decide in the coming years. Thank you.
Okay, thank you.
We have the next question coming from the line of Matthew Lofting from JP Morgan. Matt, you can go ahead.
Afternoon, gentlemen. Thanks for taking my questions. Two, if I could please. Firstly, if I can come back to CapEx, obviously underspend in the first quarter relative to the implied full-year runway. If you could just talk about how you see the phasing around CapEx from 2Q onwards, the key drivers and the extent to which you're arguably seeing increased capital efficiency, particularly through the development process in pre-salt Brazil, implying downside to that EUR 1 billion-EUR 1.1 billion for the full year. Second, sticking with Brazil, the Campos Basin block that you acquired through the 15th bid round, if you could just elaborate on the potential you see from that block and the extent to which it was a block that was specifically targeted by Galp. Thank you.
Thank you, Matt, for your two questions. You're right. As Filipe has mentioned, we have a slowdown in CapEx in the first Q, but in the year-end targets or guidance, you should consider our previous guidance of the CMD. Even though we are not disregarding to continue to work on optimization of our CapEx due to the dilution of some of the costs that we are incurred because as we mature our projects, we are being able to optimize the costs that the project is taking. I have also shared previously, which is going for the OPEX that you should count for Brazil which is around EUR 8 per barrel equivalent oil. In what relates to the block that we have won in the recent bid round, effectively it's an earlier frontier position, so it's too early to start to comment on what is the potential.
Our preliminary analysis, and it was based on which we have made our proposal, we do see that these pure exploration assets have pre-salt potential. I think it is too early to start to elaborate on that. We do need to provide all the exploration works, including committed well that has been part of our offer before starting to speak more openly and deep on the matter. We are happy for taking this block for Petrogal. Thank you.
Very clear. Thanks, Carlos.
The next question comes from the line of Thomas Adolff from Kepler Cheuvreux. Thomas, you are now unmuted.
Hello. Two questions, please. Going back to BMS-8 and your comment on the appraisal activity in the northern part of your license. I just want to clarify whether you said it's kind of confirmed your initial expectations. Is it fair to assume that the reservoir characteristics or the behavior are similar to those in the South? The reservoir looks very much homogeneous. I wanted to ask you this, whether you can confirm that, and if there's anything you can disclose also on potential initial flow rates. Secondly, on upstream production, what was the exit rate in 1Q? Thank you.
[crosstalk]
Thomas, thank you for your two questions. To clarify, in Carcara, when I mentioned the DST that we have executed, it was in the Carcara Northwest well. We have reentered in a well that we have drilled in the past, and it is within BMS-8. The North part of Carcara, which is the one that we have recently acquired, together with Statoil and Exxon. This is still too early to elaborate on that, even though we see that are similarities in terms of the reservoir potential. That's the maximum that I think we should release for the time being. In what relates to the exit production, it was around 110,000 barrels a day. We are slightly progressing, looking forward to the year-end. We continue to maintain our production guidance. Thank you.
Thank you.
The next question comes from David Mirzai from Deutsche Bank. David, you are now unmuted.
Hi, guys. Two questions from me. First on, obviously, the Replicante FPSO 7. It's coming quite a bit ahead of original 15-month ramp-up guidance. Can you say something about the critical path on future Replicante FPSOs? This timeframe, has it come down structurally? Is it down to quicker drilling, which can be carried through to future works? Secondly, obviously on the refining margins, we've had a fairly poor Q1, well aware that that's down to volatility in the market. Is there anything you can do in the current environment to improve those margins? Are you somewhat reliant on, as you say, the fuel cracks, the gasoline cracks? Thanks.
Thank you, David. Effectively, the first Replicante is for all of us in the BMS-11 consortium, a starting point in a new era. We have more units to come, this is a learning curve process. It's amazing that even with that starting point, we have just reached the plateau within 11 months. The critical path for this unit is still the connection to the gas export pipeline, which should occur, as I mentioned previously, during the second Q. Looking to the other units that are coming, what is important is the learnings that we have taken from this unit. We will be capable to execute them and to adapt in the units that are still being finished. This is the first point.
The second one is related with the normal logistics, related with the fact that some of the units are being concluded in Chinese shipyards and others are in Brazilian shipyards. There are different challenges according the logistics and according the locations where the units are. We will have to manage with different critical paths according each individual unit. One thing is for sure, everything that is related with subsea facilities is not, I repeat and I emphasize, is not within the critical path. Moving to the refining margins. First, we have followed a kind of a sweetening curve in what related to our hedging strategy. That's being consistently during the last couple of years. We do think that in a long-term series, the hedging strategy, if consistent, will end up with a neutral financial contribution, we will continue to follow that.
This is the first point that will contribute and is in our hands. The second one is accelerating and fastening our set of projects that will contribute with an additional $ per barrel. We are, I would say, between 20% and 30% in terms of progression. You may see in our premium over bench mark an additional $0.20-$0.30 that are related from that contribution. Thirdly, it is not less important is, of course, keeping the operational efficiency. We will have full conversion capacity available, therefore, we will be in a completely different position looking forward. These are the key basic things that we can do in order to protect our refining business. Thank you.
Sure. Just to be clear, you have a refining hedge in 2019, do you?
Yes. We have hedged about 25% of our annual throughput during this Q. This year, you can consider the same, which is about $3.8 per barrel in terms of the margin. For 2019, we have already covered about 20% at $4 per barrel. It's basically what we have already done. Thank you.
Thank you.
The next question comes from the line of Jason Kelly from Santander. Jason, you can go ahead.
Hi. Good afternoon. Hope you are well, Carlos and Filipe. Could I get some guidance on tax rate for the year, please? Where do you think net debt to EBITDA might end up at the year-end 2018 also? Staying with net debt to EBITDA, what do you think a floor for that measure is over the forward cash cycle and through your strategy plan? Thanks.
Hi, Jason, and thank you. I hope you are all also okay. This is typically CFO stuff, so I will pass to Filipe. Thank you.
I would say this is typical Jason question. Jason, we just had our CMD, so you should not expect us to come up with anything new at this stage so early in the year. What we said at the CMD was 40% cash tax, P&L tax closer to 50%. Now, the mix this year is obviously different from what we had anticipated, so much stronger in E&P, much weaker in downstream. The P&L tax should be a bit higher than anticipated, but not materially different. Same message on our net debt to EBITDA. Yes, we are at 1x now. We don't see our net debts changing much. We do see our EBITDAs going up, but we're not giving you different messages on floor and redeployment of capital at this stage. This is inorganic transaction driven, if any.
The message at the CMD was we will carefully monitor opportunities where we have a competitive advantage, and we may or may not be able to do this. Thank you.
Okay. Many thanks.
The next question comes from the line of Biraj Borkhataria from Royal Bank of Canada. Biraj, you can go ahead now.
Hi, Carlos, Filipe. Thanks for taking my question. I have a question on Brazil and FPSO7. How long can you maintain plateau production without hooking up to the gas export pipeline? I know you're at plateau now, but will you need to curtail oil production back ahead of time before you connect the gas pipeline? Then the second question is on maintenance. Do you expect the maintenance impact to be more in Q2 than Q1? Thanks.
Hi, Biraj. Good morning. In relation to the FPSO number seven, what is limited in the increasing more the usage of the unit is the second that we have in terms of gas flaring. Therefore, the unit could be maintained as long as we intend up to the moment that we will be capable to keep the gas export connection. In terms of the typical curve of production, what we are doing is looking in an holistic way in order to guarantee that the global Lula reservoir is managed, not only looking up to this unit, but taking an holistic approach for the global reservoir in order to extend as much as possible or taking in consideration our long-term goals in terms of recovery factor.
You should bear in mind that we continue to work towards the 40% recovery factor or beyond that, depending on technological solutions and managing the reservoir in a long-term perspective rather than looking to the short term. The second question was related with the maintenance. In what relates to maintenance, yes, we will experience more maintenance plans planned for the second and the third Q. I also recall all of you that we have considered in an annual basis about 4,000 barrels a day in terms of the impact of those maintenance that are planned for recovery and also for some inspection obligation activities. All the units will be maintained with the exception of precisely the FPSO number seven. Thank you.
Thank you, Carlos.
The next question comes from the line of Michael Alford from Citi. Michael, you are now unmuted.
Thanks for taking my questions. Good afternoon to you both. I just have a couple left, actually. Just firstly, could you maybe update a little bit more on the unitization processes going on in Brazil? Clearly, some of that will impact production, I guess, guidance. I just wondered whether you could give an update on those processes, please. Secondly, just on Angola and Kaombo, I just wondered whether you could provide a little bit more update as to whether the project's now back on schedule from a timing perspective and when we should expect first oil from both the first FPSO but then the second FPSO, please. Thank you.
Thank you, Michael. In relation to the unitization, you know that the Lula process is undergoing. The only thing that has been done, it was an amendment to the AIP that has been submitted recently to the ANP. We will think that the process might be ended during the second quarter. To clarify and to have all of us in the same page, we did consider that the effects of the unitization in Lula will enter in place from 1st July onwards. That's what we are counting on. In relation to Iara Reservoir, starting by Birigui. Birigui will follow a process that is similar the one that we have done with Lula. The present status is that we have already submitted to the ANP all the process back this February.
In what respects to Sururu, the initial track participation and also the redetermination triggers have already been agreed. Therefore, we are now preparing the process and the agreement to be submitted to ANP during the second half of this year. Finally, we are working on Atapu. It's the process that is in early stage. The parties are still negotiating the tracking participations and the redetermination triggers. Therefore it's something that is still under negotiation. We still have, because most of the assets we are required to unitize, we still have CPR East, which is one of the carved parts of the BMS-24 where Jupiter is also placed. That process is still also under analyzed by ANP. We expect that the process might be concluded by the year end.
Basically it's a sum up for the unitization process to clarify for once where we are. Moving to Angola. Angola, we have already the first unit, the Kaombo Norte in place. Now works are being provided in a way to have the unit with the first oil during this summer. I would say in the second half, but most likely still during this summer. In what respects to the second unit, we expect to have the second unit just in the year after. It's one year after also the first unit being producing. This is the summary that we can provide to you. Thank you.
Thanks, Carlos. Much appreciated.
The last question comes from the line of Mark Hoffler from Jefferies. Mark, you can go ahead now.
Hi there, everyone. Thanks for taking my questions. I just wanted to come back to the downstream, please. Obviously, a pretty impressive premium to the benchmark achieved in the first quarter. Can you say a bit more about how you're able to do that? I suppose particularly regarding the comments around the raw materials that you're processing and the different crude. Then can you also talk a little bit, please, about the margin environment into the second quarter? I suppose on that side of things, if you're seeing any remarkable trends given the movement up in oil prices over the course as well. Thank you.
Thank you, Mark. Effectively, I tend to agree with you. I think we are dealing with this process quite well. First of all, embedded in the premium over benchmark is related with some additional efficiency that comes from the projects that are implemented. It's energy efficiency, so it's endogenous. The second point is related with the fact that we are selling gasolines for the U.S., which has a premium over the benchmark that is relevant. The third point is still the optimization of the sourcing. That has really been one of the relevant contributions for the elements. All in all, and looking forward, you should bear in mind that we have forecast and assumed for 2018, the refining margin at $3.5 per barrel.
We still have an effect that it will have a higher impact in the coming Qs which is the fact that our consumption is based on natural gas. The natural gas is still indexed as a kind of a time lag effect in the system. When looking to the forwards of the refining margins, what we see is that the gasoline season is coming and the cracks over benchmark are improving. The middle distillates are also recovering. The only one that we are not seeing reacting positively is the fuels. There are some justifications for that, some trends. One of them might be related with some de-stocking that the market is anticipating due to the IMO, some trends related with the shipping activity. Still, for short term, to have a more based and strong position.
Going forward, we do see that the margins have all the conditions to continue to grow because once the Brent will stabilize and the demand will continue to grow, we will see that as a positive trend. Thank you.
Great. Thank you.
Well, thank you very much, everybody. I think we conclude now the conference call. Thank you very much.
Thank you for joining today's conference. You may now disconnect your handsets.