Good afternoon, ladies and gentlemen. Thank you for standing by, and welcome to the Total's First Quarter 2019 Results Call. At this time, all participants are in a listen-only mode then will be a presentation followed by question-and-answer session. [Operator instructions] I must advise you that this conference is being recorded today, on Friday the 26th of April 2019. And I would now like to hand the conference over to your host today, Patrick de La Chevardière, CFO of Total. Please go ahead, sir. Patrick de La Chevardière: Thank you. Patrick de la Chevardière here. Let's go straight to the results and then to the Q&A. The environment has been volatile, starting the year weak but then gaining strength. And in this environment, we reported first quarter 2019 adjusted net income of $2.8 billion or $1.02 per share; debt adjusted cash flow of $6.5 billion, up 15% year-on-year; and very strong organic free cash flow of $3.2 billion, up 18% year-on-year, with a pre-dividend cash flow breakeven below $25 per barrel. We are in line with our February presentations and on track to grow cash flow over the coming quarter progressively as our major projects ramp up. Total has been moving at a very rapid pace in the recent years, continuing to deliver on production growth, cost reduction, portfolio management and capital discipline. One of the highlights marking our progress has been the creation of the new integrated Gas, Renewables & Power or iGRP segment. Effective this year, the LNG business, including the Upstream and Midstream operation, is being reported as part of the iGRP segment so we have provided restated past results, and the current results reflect this new format. Also this year, we have revised some of our indicators, and we have, of course, implemented IFRS 16. The…

[Operator instructions] And your first question comes from the line of Alastair Syme of Citi. Please go ahead.

Patrick, two questions. You set these cash flow targets for 2019 back in February. I just wonder if you can quantify the impact the weaker spot gas prices might have had on this quarter, both in terms of the conventional business and also the IG business. I'm just trying to figure out that -- if gas prices remain weak through the course of this year, is that going to have a material impact on your guidance? And I'll give you my second question. I guess P1 made some comments on the fourth quarter results around U.S. shale that I think had been interpreted in different forms in the market. I just wonder, given all the activity in the U.S. in the last couple of weeks, whether you can maybe set the record straight around Total's view on U.S. acquisitions. Patrick de La Chevardière: Thank you, Alastair. I'm glad to see that you definitely recovered from our trip to Moscow. To your question about CFFO target. We don't change the guidance. It is true that currently spot prices are affected by a mild winter, and we see gas price going down on Europe and in Asia, including, on top of that, Henry Hub losing $1 per million BTU. And we expect short-term pressure on gas price, not only because of that but also because of supply. I'd like to remind you that most of our equity LNG is sold long term. There is one exception this quarter about Yamal. Because Yamal started up one year in advance, and the long-term contracts are not yet active so Yamal had to sell its gas on spot market, mainly in Europe where the gas price is weak at the moment. We expect Henry Hub to remain below $3. In Europe, on the other hand,…

Patrick, can I just draw you back on the first question on the guide? As you think year-on-year, is there a way of trying to help us quantify the impact of weaker spot prices on the overall Upstream business? Patrick de La Chevardière: I'm sorry I can't give you the numbers. I don't have the numbers in my dossier. Wait for July, and we will have a better understanding of the actual effect after two quarters.

Your next question comes from the line of Oswald Clint of Bernstein. Please go ahead. Your line is open.

Yes. I'd also like to ask about the integrated Gas, Renewables & Power business. Certainly, with the new return on capital employed numbers you've broken out for that division, the 7.4% that it's done over the last 12 months, I think that fits in the 7% to 9% range that you kind of indicated back last September at and around $60, which is what we've had in that time period. So I just want to get a sense from you what has to happen to get that up closer to the top end of that 7% to 9% ROACE target, please that's my first question. And then, secondly, I wanted to ask about marketing. You said the marketing areas were generally quite stable. I think optically, of course, you're still down 7% year-over-year. I also remember Momar talking about the retail expansion initiatives adding probably quite easily $100 million per year. So my question is -- I don't really see that coming through here this quarter. Is that part of the strategy working? Is the retail expansion program really starting to deliver the earnings? Patrick de La Chevardière: The first question about iGRP. First, there is the effect of the start-up of project at the moment. We just started Ichthys. So let's add Ichthys at full capacity with its Upstream and then we will have the full benefit of Ichthys in iGRP. That's the first comment. And this is a very profitable Upstream part in the LNG business, the Upstream of Ichthys. Second, there will be more low-carbon electricity, I think so, with the run of some CCGT that we bought recently. And having as an objective a double-digit ROACE, I can't say I am 100% confident. But the range 7% to 9%, I am confident. We are in the low side of this range at the moment because we just started some operation. About M&S, M&S, the result is quite stable. The net operating income is quite stable from quarter to another at around $350 million per quarter. Then we see the adjusted net operating income in 2018 was -- the result of this quarter in 2018 was due to the sale of TotalErg that we lose. We don't have any more operation in Italy so we don't have the benefit of TotalErg marketing under the Total brand anymore. I think those are the main effect.

And your next question comes from the line of Biraj Borkhataria of RBC.

I had a couple, please. The first one is could you just update us on the next steps for the LNG project in PNG and how you expect to progress towards FID and the rough timings? And the second one is just could you provide an update on your activities in Argentina in the Vaca Muerta? That would be helpful. Patrick de La Chevardière: Let's start on Argentina because it is quite simple. We recently have signed an agreement for tax purposes in Argentina where we pay some tax in advance, and we're committed to upgrade our DD&A. So in Argentina, the overall financial situation is difficult. We are quite happy technically with what we are doing on the Vaca Muerta. We are strongly positioned. We have about 300,000 -- or more than that, 300,000 net acres in dry gas, wet gas and oil windows. It's low cost, unconventional. The question mark is, are we ready to put a lot of fresh money in the country at the moment? That is the question. Second question about Papua New Guinea. Total has 40% before government backing and 31% after. We have signed an agreement, Exxon and Oil Search and Total, what is called a gas agreement with the State of Papua New Guinea defining the fiscal framework of the Papua LNG project. This is a very important milestone, and this allow us to enter into the FEED phase that will lead to FID in 2020. I remind you that the project consists of two train of 2.7 million ton per year, and we unlock about a billion barrels of reserves.

And your next question comes from the line of Thomas Adolff of Crédit Suisse. Your line is now open.

Just going back to Alastair's question on gas prices and your exposure to spot. If we said the broader market is roughly 75%, 80% contracted medium and long term and the rest on a spot or short-term basis, perhaps you can comment whether your portfolio is similarly positioned or whether you have less spot exposure, considering the outage on Yamal LNG. And secondly, just staying with LNG. Your guidance is for 40 million tonnes by 2020, both equity and third-party gas. You've got a very good pre-FID hopper, and I wondered what your base case is for 2025 or 2020 -- 2030. Patrick de La Chevardière: Thank you, Thomas. First, about gas price, as I said to Alastair, basically, our equity gas is sold long term. Some portion of it is spot like Yamal at the moment because the long-term contract are not yet active. But basically, it's long term. Then you have -- and this is roughly 50% of what we sell on the market. The next 50% is contracted volumes that are sold either through formulas linked to Brent or Henry Hub or either sold on the market on a spot basis. I would say that a vast majority -- we try to have the vast majority of our contracted volumes, equity or not, committed to a long-term buyer. There is a remaining spot basis volume on the -- in our portfolio that we sell, and we would -- and we are developing a network of regas terminal to have outlet for this gas, and we have enough. For instance, we have a large base in Europe at the moment. We have projects in Africa, in Cameron for instance, that will help us to sell our gas on a spot basis, taking advantage of the arbitrage which may happen by time to time in different locations. But I think that more important for us is that even if, today, spot prices are weak, which is the reality, this does not jeopardize our long-term view. There is no oversupply that we see on the market by 2024. There is maybe an oversupply today. Maybe, I said. But we don't see foresee any more oversupply by 2024. Demand is growing currently at a rate of more than 10% a year, and we are quite confident that our strategy to increase our exposure to LNG is the right one. So next question was about what is the guidance beyond 2020 for LNG. As you noticed, we set a target of 40 million tonnes per year by 2020. The equity production by 2025 will be around 30, 3-0, million tonnes per annum, and this is representing a growth of 50% basically. Trading is half of the equity production today. So this may be helping you to figure out what could be the guidance by 2025, having in mind this equity production by 2025 of 30 million tonnes per year.

And your next questions come from the line of Jon Rigby of UBS. Please go ahead. Your line is open.

The first is on Asian gas, which has seen a big pick-up in production levels since the start of last year. And obviously, some of that laterally has been Ichthys. But I just wondered -- a couple of things. One is, where are we with Ichthys? Are we still just running with 1 train? The second question is, is it all -- related to that, is GLNG seeing some better performance in terms of gas production in the last sort of three or four quarters? Just trying to get an idea about the trajectory of production there. And the second, just sticking on the gas theme and the LNG theme, is I was struck by your investment into the Driftwood because you already had exports, I believe, out of Sabine and obviously with the Engie assets as well. So can you just sort of elaborate or give a bit more color around the strategy around how you allocate investment dollars to U.S. export? I would have thought, to my mind anyway, perhaps an expansion of your existing Engie positions might have been more economic, but I'd just be interested to hear your perspective. Patrick de La Chevardière: Asian gas, currently, two trains started up at Ichthys in October and in November actually. The ramp-up is ongoing. The production currently in March was about 300,000 barrels per day equivalent. I remind you that both two trains are filling their production on an oil-related formula, mainly to Japan as we are -- this is a Japan Inc. project. I'd like to remind you also that we -- as a partner, we are not so happy with the cost increase we were facing end of last year that we reduced our stake by 4%, we divested 4%, and that currently our remaining stake…

And your next questions come from the line of Lydia Rainforth of Barclays.

Two questions, if I could. The first one, just on the Downstream and the refining environment and just what you're seeing at the moment and whether you're already seeing any impact from the IMO side as yet or how it can all play out. And then the second one was around what you're looking at in terms of costs and CapEx. Are you seeing any either inflation on the CapEx side or on the cost side? Is that proceeding according to what you expected at the Capital Markets Day? Patrick de La Chevardière: Our trading people, on IMO 2020, started to see an effect on the market, started to see. Actually, on the prices of light oil, we -- I haven't seen in the first quarter any impact of the IMO 2020. It may be too early. It may be a matter of a quarter or two. On the cost side for inflation, the question is has cost deflation bottomed out. I don't think so outside of the U.S. We are not in the U.S. onshore, I remind you, and we are not willing to go, I repeat it. Outside of that, we don't see inflation coming back currently on the market. Thank you, Lydia.

And your next questions come from the line of Irene Himona of Societe Generale.

My questions are both on cash flow items. Firstly, if we look at DD&A in the quarter, leaving out asset impairment, it appears that underlying DD&A jumped about 10% sequentially. Obviously, there is a lot more production. I just wonder if you can give us some full year guidance here. Should we expect the Q1 level to -- sort of to remain for the rest of the year? And then secondly, on working capital. I realize you look at free cash flow excluding this, but there was a substantial increase in Q1. Oil prices are even higher now. You told us in the past, I believe, that you have a sort of committee watching this or managing it. I wonder, again, if there is any guidance you can give us for the full year in terms of working capital, please. Patrick de La Chevardière: Your first question on DD&A, this is true that there is an increase in first quarter '19 of about $0.30 per BOE. This is due to the start-up of cash equity projects like Egina, Kaombo and Ichthys. As we are expecting production to continue and grow, I see that I can expect DD&A to continue and increase following the production increase, start-up after start-up. The working cap, honestly, I'm not very happy anyway because we were in a $60 environment first quarter this year. Two elements in that. We will try and control the working capital once again in the second quarter. But there is an effect of the oil price, which is still rising, which has an effect on the inventories, and it will have an effect on the working cap. So I can't say that I am not happy to see the oil price at $70. I am happy with that, but this will have an effect, in my view, on the working cap of the second quarter.

And your next question comes from the line of Christopher Kuplent of Bank of America. Please go ahead.

Patrick, just wonder whether you could give us a little more detail on the impact from IFRS 16. Is that another reason why D&A sequentially has increased? Also, any color you can give us on how the full year guidance you gave us in February is broken down by quarter? Is this -- should we divide that by 4? Can you give us some sort of insight, now that you have the Q1 result in front of you, how much of net income and, more importantly, net cost of debt as well as CFFO items have moved because of the IFRS alone? And second question -- and that's really just more looking for confirmation. Your $15 billion to $16 billion full year CapEx guidance includes things like payments for Arctic two. Please, can you confirm and maybe give us a little bit of an insight how much -- now that the deal is closed, how much cash outflow you are expecting in 2019 from Arctic two? Patrick de La Chevardière: So IFRS 16, a very interesting topic. This has an effect of 3% on gearing. This will remain stable. The impact on capital employed is between $5 billion and $6 billion. Actually, I think it is $5.7 billion in the first quarter. It has an effect of about $1 billion per year on our debt-adjusted cash flow; so per quarter, $200 million to $250 million. On the net income, it has no effect, and those guidelines which were given in February remain valid. The CapEx guidance of $15 billion to $16 billion are including the Arctic LNG 2 payment. The $600 million that we have paid already and that's it. I mean in 2019, we will pay $600 million for Arctic LNG 2. And it's included in our $15 billion, $16 billion guidance.

Okay. Can I just ask one follow-up on Arctic 2? You've got a CAGR in terms of your top line out there for 2022. Would Arctic 2 be additive to that CAGR, please? Patrick de La Chevardière: It's included.

And your next question comes from the line of Lucas Herrmann of Deutsche Bank. Please go ahead.

I'm not sure if I should be saying thank you as well for all the help over the years because I'm not aware if this is your last conference call or not, but whatever. Many thanks. And now the irritating part. I wanted to push you a little bit more on Lydia's question around cost, not least on LNG, given the level of activity that's starting to build in the industry and the number of you that are trying to push projects into what seems like a gap that's going to be filled very quickly. So question one was really just to check and go back on Lydia's question of whether you're seeing anything happening around LNG. Secondly, I wonder whether you care to comment on profile around Tempa Rossa, what's happening and also make an observation on Cameron, the other project that is due to start up this year. And thirdly, very simply, the guidance you gave on cash flow per $10 move, how does that split, if at all, between Upstream and iGRP? Patrick de La Chevardière: Okay. Thank you for your word, Lucas, but this is not my last call. The last -- my last call is in July. On cost, honestly, when I said to Lydia that I don't see -- we don't see any cost inflation in our main businesses, which is deep offshore, conventional onshore, offshore and LNG, this is based on our thinking about -- of what we see actually on the market. I remind you that Chinese yard are currently competing with Japanese, Singaporean and Korean yard. On top of that, now Russia is building its own capacity to build LNG plant. So we see strongest competition, a large capacity available, which lead us to think that we are not yet at the time where we will see prices going up. Thank you for the question on Tempa Rossa because, honestly, as you know, technically we are ready. Italy has always been a difficult country for us. We are still waiting for an authorization from the administration. Shall I say it is a mess? No, not exactly, but we are not happy.

You can't comment at all, can you, Patrick? Patrick de La Chevardière: We will touch that obviously in May. Can you repeat your question about the split between E&P and iGRP?

Yes. The guidance on -- sorry, the guidance on sensitivity, $10 move is $3.2 billion of cash flow or 2.78, I can't remember quite offhand, on EBIT. Given you've split out the LNG activities -- or a number of the LNG activities which have a sensitivity to the oil price, how does that cash impact split by divisional profit impact as well split by division? Is that clear? Patrick de La Chevardière: About -- I would say that in our sensitivity, about 5 -- no, I don't want to give you any figure. I'm going to give you -- I'm going to make a mistake. So no, I don't have the answer. But I understand your question. Ask it again in July, and for sure, I will answer.

And your last question comes from the line of Jason Gabelman of Cowen.

I just wanted to touch on share buybacks. I know in the press release, you said, in a $60 oil price, you would buy back $1.5 billion this year. Clearly, oil prices are well above that. So just looking for updated thoughts around what level you think share buybacks could come in at if oil prices stay at this level or if Brent persists above $70 a barrel for the rest of the year. Patrick de La Chevardière: Okay. First quarter -- last year, sorry, we gave a guidance of $1 billion at $60, and we actually buy back $1.5 billion because we were at around $70, $71, if I well remember, per barrel. We are currently at the moment buying at a pace of $1.5 billion a year. But what we have done in the first -- last year is an idea of what can be done. But it's very premature to believe that the oil price will remain at $70 for the full year. Honestly, I have no idea. It was $60, first quarter. We are temporarily maybe at $70 at the moment. So I don't like to make forecast on oil prices and taking the conclusion of what can be a very wrong assumption, so I'm sorry. At the moment, we are on a $1.5 billion program at $60. Last year, we gave the guidance of $1 billion, and we did $1.5 billion. Then up to you to dream a little bit. Thank you. That was the first quarter results, which are another example of Total's ability to deliver on clearly articulated strategy. As you see, we are growing our cash flow effectively, investing in growing businesses and using free cash flow to increase returns to our shareholder. Bye-bye, and see you in July.

Thank you, ladies and gentlemen. That does conclude your conference for today. Thank you for participating, and you may now disconnect.