Earnings Call: Q1 2018

Apr 27, 2018

Good morning, ladies and gentlemen. Please welcome to Gulf's First Quarter 2018 Results Conference Call and Strategy Execution Update. I will now pass the floor to Mr. Dias, Edo Dias, Head of Strategy and Investor Relations. Good morning, ladies Welcome to our Q1 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. Filip will then go through the results. At the end of the presentation, 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 cash and earnings statements 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, and good afternoon to you all. I believe that today, we should be a rather straightforward update considering our recent Capital Markets Day. So to start, let me give you a quick overview on what happened during this Q1. We saw Brent traded as high as $70 per barrel. But 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. And this, as we work on expanding our projects pipeline with new promising assets and solutions aligned with our strategic guidelines that we well know. The cash flow generation from operations in the quarter reached EUR 245,000,000 in spite of a significant investment in working capital, which Colette will cover later on. Within this cash flow, you will see that group EBITDA was up 17% year on year, mostly supported by the E and 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 dollar. Regarding the downstream businesses and besides the lower benchmark margins, I highlight the planned maintenance in our Siems Hydro Cracker, which was executed safely. But 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 regard to participating in the 15 concession bidding round and acquiring 1 exploration block in Campus Basins. 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 enable us to take advantage of selected opportunities that might arise in the market, but always, I underline, always solving a financial discipline and a value over volume strategy. Let me just briefly cover the performance of our division and starting by the E and P on Slide 6 of our presentation. Production increased Q on Q supported by the continuous development of Lula and Iracema in Brazil. This came mostly from the FPSO No. 7 placed in Lula South, which had its 6 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 derisk 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 2 new units to come online in Brazil during the second half of the year. In Iara, we started the EWT in Chururu Southwest. These tests will provide useful information to optimize the complete drainage plan for this reservoir. Meanwhile, and in what respects to Carcara, we continue to work with our partners on the appraisal campaign. We have just concluded the DSP in Carcara Northwest, which will enable us to better understand the quality of the reservoir and its potential productivity. We are currently assessing that data. Now moving to Angola on Slide 7. In Block 32, the FPSU to be allocated to Colombo North 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. So we should start production during the second half of this year. Let's move now to the downstream on Slide 8. Refining had a challenging quarter apart from the scheduled maintenance that we have anticipated in our senior refinery hydropractor. We all saw a significant decrease in refining margins, which was well flagged on the European benchmarks, mainly due to the sharp increase in oil prices and the strong decline of gasoline and fuel oil cracks. Our benchmark was down 47% Q on Q with Galps 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 edge volumes during the period. All in all, our implicit refining margin was down only 22% Q on Q 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 dollar per barrel. There is already a part of this value on the spread achieved during this quarter. Finally, margins have slightly recovered yearly 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 benefit from the Iberian economic momentum and the consolidation that we have 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 training 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 Q on Q, but with better margins. So that's it from me. I will now pass to Philippe that goes in the financials. Thank you. Thank you, Carlos, and good afternoon. Just a quick overview from you on the Q1 numbers, which should be fairly straightforward. I'll start with the P and L on Slide 10, where group EBITDA in Q1 was up 17% year on year to €455,000,000 This is driven by much higher upstream contribution. A slight decrease quarter on quarter was driven by refining headwinds and the weaker dollar. E and P EBITDA of €293,000,000 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 price. You will have seen that starting this year, we are booking as an expense all exploration, G and A and G costs, geological and geophysical costs. These are now accounted for under operational costs, but 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 122,000,000. This is down both quarter on quarter and year on year and mostly on the lower refining margins, but also impacted by the hydropractor maintenance and the dollar depreciation. Gas and Power EBITDA was up $14,000,000 year on year, reflecting the slightly better European gas prices environment. And if you recall, Q1 2017 has been negatively impacted by sourcing restrictions in Algeria. So there's a bit of a base effect here as well. Below the line, I would only highlight the €39,000,000,000 in associates and the higher P and L taxes, mainly as a result of the higher E and P results mix. RCA net income was €135,000,000 during the period and €130,000,000 under IFRS. Non recurring items were all related to the extraordinary taxes on the energy sector. On Slide 11, CapEx was €146,000,000 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 $33,000,000 will be payable only later this year And same for the $17,000,000 or so of the first payment for the acquisition of the 3% stake in BMS-eight, which we announced last year. On Slide 12, we have cash flow from operations of €245,000,000 This is already net of €159,000,000 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 Sinesh ports at the very end of March. On Slide 13, net debt was stable at around €1,900,000,000 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 debt. We have already refinanced most of the 2018 maturities. As for liquidity, we had around €2,500,000,000 between cash and undrawn credit lines. And this is it for me. We are now happy to take your questions. Thank you. Hello. Thank you very much. Just maybe a bit more backdrop question. So shortly after your aftermarket stay update, But 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 technical problems. So in relation to Mozambique and in what respects to namely to Mamba. So after the Exxon entering the consortium, we are analyzing how we can optimize the development concepts, and 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. So basically, 2018 is a year to mature and to better appraise, which are the alternative solutions to have the most profitable and competitive projects in the business. Thank you. Thank you very much. Just a quick follow-up. So 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 we you should consider, all of us, it's basically that coral is progressing according to plan. And therefore, we will invest in Mamba, so in onshore, basically to deepening and to develop the concepts that could be the alternative solution for Mozambits. So there's some CapEx that has to be spending, but for the concept development process. 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 $9.2 per barrel ticked up a little bit in the quarter. Is that simply the startup costs on the Yara, EWT or the further declines in Angola? Or perhaps talk about that number, what's happening there and your expectations for the rest of the year, please? And also related to Brazil, I think one of your key milestones this year was some of the EOR enhanced recovery initiatives on Lula were a third of the way through the year. So perhaps you could give us an update on where you are with those initiatives, please? Thank you. Oswald, good afternoon. So in relation in respect to the OpEx comparing Q1, Q1 is slightly the difference. First, we have an additional unit. So we are executing the EWT in Sururu, which means that we have additional costs. We have also had during the period also some constraints on the CIDADA and the Juarez. And of course, there are also some credits in Brazil that has been considered in the 4Q of 2017 that are not happening in the 1st Q of 2018. So all in all and going forward, if you should consider a fever, you should spend around $8 per barrel. In what relates to the other point, so the OR, so Galt, of course, has its own and as always autonomous analysis in what relates to research and development and the studies that we are performing. But we are working together with our partners in BMS-eleven in order to provide an optimization in what respects to the infill assessment. So it's something that is an ongoing project within the consortium. Thank you also. The next question comes from the line of Alwyn Thomas from SVNP Paribas. You can go ahead. Good afternoon, gentlemen. Can I just ask on Petrogal? As you move towards a free cash flow generating position, can you just talk a little bit about how the cash can be redistributed over the next, I guess, 2 or 3 years? And whether that's going to come more likely to come in the form of dividends, loan repayments or used to reinvest in Brazil, whether you keep a country or expect to? And 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, Alan. Starting from the first question that you have addressed. So 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% 15%. And depending on the context and environment and the progress of our operations, we will, every year, review our dividend policy accordingly, the debt environment. So effectively, it's basic where we are today. Sorry, I meant that Petrogel, just in Brazil, how you add it to that? In Brazil, yes. In Brazil, looking into Brazil. So Brazil, as I've as you saw during the last, I would say, half a year, we have been actively participating in the bid round concessions that held in Brazil, and we will continue to do that. So we have basically 2 or 3 options to 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, and then I used to say, we have a long run to go in order to extract more value with incremental projects on the existing assets, and we have quite a time to continue to derisk and to show and to prove their endogenous value. And we only consider to redistribute and send back to the shareholders some dividends if we will not find additional investment opportunities. So we are very an open minded way on approaching through Petrobrasil to continue to expand our activity. Is that clear for you? Yes. Thank you. Carcara progress? Okay. Let's go to the Carcara. So in Carcara, I would say that we can look to the Carcara as an old BMS-eight plus the Carcara Nors. So we are working together in the JV with Statoil. In order to continue the derisking program, we outperformed the DST in the Carcara Northwest that has been done in the last 3, 4 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 Guni Zhilma area, which is something that we are now taking in our hands. And we expect that in the second half of the year, we might step toward the north of the Carcara. But it's something that is being managed in a way to guarantee that we have all the conditions to start that process. So all in all, the appraising the global appraisal that is being performed in this BMA 8north 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 Matt Loftin from JPMorgan. Matt, you can go ahead. Yes. Good afternoon, gentlemen. Thanks for taking my questions. 2, if I could, please. Firstly, just on if I can come back to CapEx, obviously, underspend in the Q1 relative to the implied full year run rate. 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 presold Brazil, implying downside to that €1,000,000,000 to €1,100,000,000 for the full year? And then second, sticking with Brazil, the Campos Basin block that you acquired through the 15th bid round, if you 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. So you're right. So the and as Felipe has mentioned, we had a slowdown in CapEx in the 1st Q. But in the year end targets or guidance, you should consider our previous guidance of the CMD. Even though we are not considering 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. But I have also shared previously, which is going forward, the OpEx that you should count for Brazil, which is around $8 per barrel equivalent oil. In terms of the in what relates to the block that we have won in the recent bid round, effectively, it's an earlier in earlier frontier position. So it's too early to start to comment on what is the potential. But our preliminary analysis, and it was based on which we have made our proposal, we do see that these fewer exploration assets has a pretty solid potential. And 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 Matsu. We are happy for taking this block for Petrobras. Thank you. Very clear. Thanks, Carlos. The next question comes from the line of Thomas Adol from Credit Suisse. Thomas, you are now unmuted. Hello. Two questions, please. Going back to BMS-eight 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. So is it fair to assume that the reservoir characteristics or south? So the reservoir looks very much homogeneous. And I wanted to kind of 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. Well, Thomas, thank you for your two questions. So to clarify, in Carcara, when I mentioned the DST that we have executed, it was in the Carcara Northwest well. So it's we have reentered in a well that we have drilled in the past, and it is within BMS-eight. So 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 our similarities in terms of the reservoir potential. So 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. And we are slightly progressing according and looking forward to the year end. We continue to maintain our production guidance. Thank you. Thank you. The next question comes from David Muzae from Deutsche Bank. David, you're now on mute. Hi, guys. Two questions from me. First on obviously the direct to FPSO7, it's coming quite a bit ahead of original 15 month ramp up guidance. Can you say something about the critical path on future FPSOs? This time frame, has it come down structurally? Is it down to quicker drilling, which can be carried through to future works? And just secondly, obviously, on the refining margins, we've had a fairly poor Q1, well aware that that's down to volatility in the market. But is there anything you can do in the current environment to improve those margins? Or are you somewhat reliant on, as you say, the fuel oil cracks and the gasoline cracks? Thanks. Thanks. Thank you, David. Effectively, the first replicant 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. But it's amazing that even with that starting point, we have just reached the plateau within 11 months. So the critical path for these units 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 units that are still being finished. So 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. So there are different challenges according to logistics and according to locations where the units are. Therefore, 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. So moving to the refining margins. 1st, we have followed a kind of a sweetening curve in what's related to our hedging strategy and 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. And therefore, we will continue to follow that. So this is the first point that we'll contribute and is in our hands. The second one is accelerating, is fastening our set of projects that will contribute with an additional dollar per barrel. So we are, I would say, between 20% 30% in terms of progression. So you might see in our premium over the benchmark an additional $0.20 to $0.30 of dollar that are related from that contribution. Thirdly, and it is not less important, is, of course, keeping the operational efficiency, but we will have full conversion capacity available. And therefore, we will be in a completely different position looking forward. So these are the key basic things that we can do in order to protect our refining business. Thank you. Cool. And just to be clear, you have refining hedge in 2019, do you? Yes. We have hedged about 25% of our annual throughput during this Q. And this year, if 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. So it's basically what we are what we have already done. Thank you. Thank you. Thank you. The next question comes from the line of Jason Kelly from Santander. I hope you're well, Carlos and Philippe. Could I get some guidance on tax rate for the year, please? And where do you think net debt to EBITDA might end up at the year end 2018 also? And 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 already also okay. So this is typically CFO stuff. So I will pass to Philippe. 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. So what we said at the CMD was 40% cash tax, P and L tax closer to 50%. The mix this year is obviously different from what we had anticipated, so much stronger in E and P, much weaker in downstream. So the P and 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 one time now. We don't see our net debt changing much. We do see our EBITDA is going up, but we're not giving you different messages on floor and redeployment of capital at this stage. So this is inorganic transaction driven, if any. And 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. Okay. Many thanks. The next question comes from the line of Biraj Borkhataria from Your Royal Bank of Canada. Biraj, you can go ahead now. Hi, Carlos. Thanks for taking my question. I had a question on Brazil and FPSO7. How long can you maintain plateau production without hooking up the to the gas export pipeline? I know you're plateaued now, but do you will you need to curtail oil production back ahead of time before you can actually gas pipeline? And then 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 7, what is limited? The increasing more the usage of the unit is the same that we have in terms of gas flaring. And 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 LULAG reservoir is managed not only looking up to these units, but taking an holistic approach for the global reservoir in order to extend as much as possible using our or taking in consideration our long term goals in terms of recovery factors. So you should keep in or bear in mind that we continue to work towards 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. In what relates the second question was related with the maintenance. So in what relates to maintenance, yes, we will experience more maintenance planned for the second and the third Q. And I also recall all of us 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. And all the units will be maintained with the exception of precisely the FPSO number 7. 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. So 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. So I just wondered whether you could give an update on those processes, please. And then secondly, just on Angola and Quambo, I was just wondering whether you could provide a little bit more update as to whether the project is now sort of back on schedule from a timing perspective and when we should expect sort of first oil from both the first FPSO, but then the second FPSO, please? Thank you. Thank you, Michael. So in relation to the unitization, that whole process is undergoing. The only thing that has been done, it was an amendment to the AIP that has been submitted recently to the AIP. We will think that the process might be ended by during the Q2. So 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 1 July onwards. So that's what we are counting on. In relation to Iara reservoir, so starting by Berbigao. Berbigao will follow a process that is similar to one that we have done with the present status is that we have already submitted to the ANP We hold the process back this February. In what respects to the track 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 INP during the second half of this year. And finally, we are working on Atapu. So it's the process that is in early stage. So the parties are still negotiation negotiating the tracking participations on the redetermination triggers. And therefore, it's something that is still under negotiation. We still have and because most of the assets we are required to unitize, with TLEV CPF East, which is one of the carved parts of the BMS-twenty four where Jupiter is also placed. And that process is still also under analyzed by H&P. And we expect that the process might be concluded by the year end. So basically, it's a sum up for the unitization process to clarify for us where we are. Moving to Angola. So Angola, we expect we have already the first unit, so the Colombo North in place. The 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 respect to the second unit? We expect to have the second unit just in the year after. So it's 1 year after also the first unit being producing. So 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 Hofeller 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 Q1. Can you say a bit more about how you're able to do that? And I suppose particularly regarding the comments around the raw materials that you're processing in the different crudes? Crudes? And then can you also talk a little bit, please, about the margin environment into the Q2? And 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. So effectively, I tend to be with you. I think we are dealing with these process quite well. So first of all, embedded in the premium over benchmark is related with some additional efficiency that comes from the projects that are implemented. So it's energy efficiency, so it's endogenous. The second point is related with the fact that we are selling gasolines for the United States, 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. So all in all, and looking forward, and you should bear in mind that we have forecast for 2,000 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 and the natural gas is still indexed to the has 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. The cracks of our benchmark are improving. The middle distillates are also recovering. And 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 destocking that the market is anticipating due to the IMO, some trends related with the shipping activity. So but still short term to have a more based and strong position. But going forward, we do see that the margins have all the conditions to continue to grow because once the brands 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 handset.