Good afternoon and welcome to the Total Second Quarter Results Conference Call. Today's conference is being recorded. At this time I would like to turn the conference over to Patrick de La Chevardiere, CFO. Please go ahead, sir.

Hello, Patrick de La Chevardiere here. By now you have seen our solid set of second quarter results. We reported adjusted net income $2.2 billion, or $0.90 per share. Compared to the first quarter, upstream benefitted strongly from the increase in the oil price, and downstream remained as robust in the second quarter as in the first. The environment has been volatile including, for example, the Brexit vote. Oil prices recovered in the second quarter from very low levels in the first quarter, and our average realized hydrocarbon price increased by 25% to $33.00 per BOE. At the start of the third quarter, volatility remains the dominant theme in the market and oil prices are again under pressure. Our response to this volatility is to continue concentrating on achieving our goal of being competitive in any environment by reducing our cash breakeven, executing on our projects, and delivering results. A major success for Total in the second quarter was obtaining a 30% interest in the giant Al-Shaheen field in Qatar for pretty much no bonus that will add high quality, low cost reserves and production to the portfolio. This is a concession and not a PSC as in the previous value chain contract, so we have access to about one third of the reserves and production. In the second quarter, we announced a reorganization of the Group with two main objectives; first, to improve efficiency by putting in place global services for all of our businesses; and second, to promote the development of a new business segment for gas, renewables, and power along the gas and electricity value chain. We are continuing to reshape our portfolio by reducing specialty chemicals, with the coming sale of Atotech on one side and, on the other side, by investing in oil and gas…

Thank you, sir. [Operator Instructions] We will now take our first question from Brendan Warn of BMO Capital. Please go ahead.

Yes. Thank you, and thank you for the opportunity to ask a question. I guess during the quarter you've accessed now Al-Shaheen. I was just wondering if you can give us some more details around either the free cash flow contributions, the break-evens, or the IRRs just so we can better understand for mid next year what that asset and that production is going to provide for your portfolio.

Thank you, Brendan. I am glad to see you first in this call. A few insights from Al-Shaheen, and of course we will be able to give you more when we will actually operate it. There is pretty much no bonus for this 30% interest we obtained. You will see the number in our annual report next year because it is compulsory, but it is pretty much extremely limited. We have been chosen by the Qataris because of our technical expertise that we have demonstrated on managing efficiently major fields like Al Khalij. And I think this is a key criteria, and we are very proud of that. It is a huge, low production cost field with a good margin, generating a few hundred million dollars per year for 25 years. And it is sensitive to the oil price. We have no capital employed because the existing installations are made available by the Qataris. And finally, investment will be recovered immediately from the current production. So, really I think this is a great achievement for us, and has, I repeat myself, pretty much no bonus. And by the way, let me clarify something important. Compared to the previous PSC, which is still in place at the moment as we will hand over mid next year, the new contract is a concession. So, with our 30% share, we have access to 30% of the production, reserves, and revenues. Maersk claims that the new contract was less attractive then their 100% share in the PSC because only 30% was offered in the new concession. But in terms of access to production and reserves, you cannot compare a 100% share of a PSC to a 30% share of a concession. In fact, it is so different. Basically I think this is what I can say, a few hundred million dollars per year depending on the oil price for 25 years, no capital employed basically.

Thank you. We will now move to our next question, comes from Biraj Borkhataria of RBC.

The first question was on Papua New Guinea. Obviously there are a few announcements out, with yours, Search, and Exxon. I was wondering, with the arrangement that's going to go ahead, what is the prospect for a collaboration with the original project and how you see that playing out? And the second question would be on -- I was wondering if you could just give us an update on the French refining roadmap, in particular La Mede and Donges, how you expect that to play out over the next year or so.

So, first question about Papua New Guinea, the Elk-Antelope field where Total owns 31% currently, where we post government back-in where we are the operator. Total is and will remain the operator and the largest shareholder of the Elk-Antelope field. We made, with Oil Search, what we believe was a fair bid for Interoil assets, taking into account related resource certification. I think our bid was in line with our capital discipline on acquisition and investment. Exxon Mobil made a higher offer, and we chose not to counterbid. Our main objective was to unblock the project by removing Interoil. And now we have Exxon as a partner, with their financing power and understanding of LNG. After we complete the exploration phase, we will move to the reserve certification period. Then we will begin evaluating the development option. Of course, we shall be discussing the potential synergies between the two LNG projects, and having Exxon as a partner is very important in that respect. It will be a long process, but we feel good about the project. The question about La Mede and Donges, La Mede as a refinery will stop at year-end as planned. And the startup of the biorefinery we will put in place there is scheduled next year, again as planned. Donges is under study with some good progress. We will see and discuss with our partner, the social partner, how to implement this project.

Thank you. We'll now move to our next question which comes from Irene Himona of SG. Please go ahead.

A question on working capital. If oil prices were to stay fairly stable at current levels, should we expect a reversal of at least some of the $3 billion first half increase in working capital, please?

Irene, thank you for your question. And it is an important question because we delivered very strong results this quarter, but we are not happy with the working capital. Working capital in the second quarter was about $1.7 billion with an inventory effect of $0.6 billion. So, the net is $1.1 billion, and honestly we should do better. We believe that in a stable oil price environment, I'm sorry, it is a volatile environment but I need to rely on an assumption. In a stable oil price environment, we should reverse this effect. All in all, think also to one thing, is that upstream division is producing more, so basically we have more receivables. The same exploration and production is investing less, so payables are down. So, the overall hand we saw last quarter, we can understand it. Nevertheless, we are not so happy with it and we try to reverse it.

Thank you. We will now move to our next question which comes from Blake Fernandez of Howard Weil. Please go ahead.

Patrick; a question for you on the tax rate, it's been in the low 20%'s for the first half of this year, and one of the main drivers is the beat on the quarter relative to our expectations. Is it fair to think, if oil continues to kind of hover at these low levels, that that is a kind of sustainable tax rate into the backend of the year? And then secondly, on throughputs on the refining segment for 2Q, they seem to come down quarter-to-quarter. I see you reference outages in the release. I'm just trying to get a sense if these are economic run cuts or if there was something that was kind of a one-off that should have throughputs returning to a more normalized level in 3Q. Thanks so much.

Okay. First question of the tax rate, I would say that basically, if you remember well, first quarter, no, let's come back. All in all, our tax rate is currently driven by the upstream division. We are close to break-even at $40.00, $35.00 per barrel. There are fields which are making losses and they are still making profit. First quarter this year, our tax rate was actually negative. This quarter it is for upstream division slightly positive. And the oil price came up during -- from first quarter to second quarter, but the gas price didn't move so much. So, our tax rate will be, is sensitive to the oil and gas price because we are near the break-even. And I am expecting, if the oil price recovers of course, our tax rate to go up gradually as the oil price goes up. On refineries, you know that second quarter is traditionally the quarter where we do maintenance. Maybe you didn't notice that also that we had some strikes which push us to cut production. Those are the two elements, even if on a financial ground the effect of this overall maintenance and strike is not so big.

So, it sounds like that should return to a more normalized rate in 3Q then.

I hope so.

Thank you. We will now take our next question from Martijn Rats of Morgan Stanley. Please go ahead.

I wanted to ask you two things. This is the first call since the Saft acquisition, and I wanted to ask you if you could summarize for us the rationale behind that investment. I'm sure there's also two angles sort of to it that you can imagine. But if you could sort of remind us which ones drove the transaction, that would be very useful. And secondly, I wanted to briefly ask you about Uganda. You mentioned a number of pre-FID projects, and Uganda was one of them. I was wondering how you see next steps and how quickly they could develop?

Yes. The first question about Saft, first of all I am quite happy to say that we catch more than 90% of the share in the first offer. And the offer is actually at the moment reopened until beginning of next week. This acquisition is in line with our ambition to expand in the electricity value chain and grow our renewable activities. I'd like to point out also that Saft, I would say -- sorry if you misunderstood myself, but Saft is only $1 billion. It is not $10 billion. Saft is only $1 billion company. We believe that batteries will play a very important role due to the intermittent nature of solar and wind energy, and that is the main rationality for it, to be part of this battery energy storage capacity business. We are following basically the same rationale as the SunPower acquisition, basically buying a leader. Saft is a world leader in the design and production of high technology batteries. And I think, Martijn, maybe you are not aware that the battery market is expected to double in the next 10 years. At the end of the day, when we invest in a renewable and now in energy storage, this is because we believe in their profitability. We are not making that for the duty of being part of this business. We are making that to make money. And electricity will be the 21st century energy, and this is why we have created the new gas, renewables, and power branch. We first want grow gas, our main business in the new segment, and the gas and electricity value chains come together. Saft is a profitable company, with a free cash flow positive, and is reducing its costs to improve its profitability. And we trust their recovery plan. The plan is to invest more to growth in the electricity storage for renewables. That's basically what I can say on the rationality on Saft. And if you have friends having Saft shares, please tell them that the offer -- the second offer will close beginning next week. Uganda, the important thing is that we have announced an agreement on the pipeline route. We have a project team finalizing the design and the engineering works before the launch of the call for tender process. Our objective is to take FID before the end of next year. As you know, Uganda represents a giant oil project that could turn into a new hub for us in East Africa. You should notice that the president of Tanzania and the president of Uganda signed late April a joint communique confirming that the export pipeline from Uganda would go through Tanzania, which is a great achievement for it.

Thank you. We will take our next question from Alastair Syme of Citi. Please go ahead. Your line is open.

Hi, Patrick. Can you just update us where you're at with Atotech and confirm to us what the Atotech EBITDA contribution is? And maybe if I could push you for one more, when you're looking at M&A, and you referenced the Interoil deal, what sort of set of macro assumptions are you using to screen opportunities?

Atotech, the process is on. We are currently selecting a short list of France bidders. The EBITDA is in the range of $250 million, $300 million a year. And we expect to sign a deal, I would say, the beginning of last quarter, something like this. And the first results we have are very encouraging. Your question about macro assumptions, honestly we have a number of upcoming projects, startups, so we do not need to sanction new projects to more money. And we have the flexibility to sanction projects when the time is right. I remind you that there was production growth. It is between 4% and 5% depending on the period you select. Costs are decreasing, and we are ready to take advantage of this opportunity when we launch the next wave of projects. There is something very important. It is that, as part of our strategy to reduce the break-even, what is important for us is to be competitive on the cost curve. For long range planning purposes, we are using oil price between $50.00 and $80.00. This is not going to help you pretty much. And we run multiple scenarios, and it mostly depends for us on the positioning of the potential projects on the merit curve.

Okay, thank you. Can I just confirm on the Atotech EBITDA, is that euros or dollars that you were giving?

Dollars.

Dollars. Thank you.

Thank you. We will now move to our next question which comes from Jon Rigby of UBS. Please go ahead.

Hi, Patrick. I have a couple of question. I'll keep it below 10. Can I just ask, on the acquisitions that you've made or the investments that you've made in renewables, so Saft, Lampiris, is there ultimately an intention to roll those together into integrated businesses? And I'm just wondering how that plays out with obviously your biggest position, which is SunPower, which still has minority interest. So, I can see at the very high level that you have some sort of integrated -- or integration potential between solar and battery, but I just wonder how that might play out in practice. And then just my second question just on the results on the affiliates line, which you addressed in your speech. But just on the upstream, given the sort of gas lags to oil price, etc., I was just wondering how in the upstream the result was so strong, sort of significantly above 1Q and pretty much in line with this time last year, but obviously against a very much lower oil price. Is it all volume, or is there other stuff going on as well?

So, first question about Saft and potentially integrating the businesses between SunPower, Saft, and maybe others, as a matter of principle we manage our affiliates on a mark-to-market basis. This is to say that if SunPower buys batteries, it might -- it must be through the most competitive supplier. If this supplier is Saft, perfect. If there is ultimately a better supplier for SunPower, it is up to SunPower to select the better supplier. On top of that, we have minority interest in SunPower, and we must leave SunPower alone in their own decisions and in their calls for tender. That's for the potential integration. Of course, Saft, SunPower are part of the renewable division, and both are key elements in our strategy, one for solar panels, the other one for batteries.

So, I should think of it as a sort of confederation of businesses. Is that right?

Actually, yes. That's very interesting. You remember that we have a few interests in Russia, namely Novatek, Termokarstovoye. And if you read the communique made by Atotech, I think that was yesterday, it is obvious that their results improved, and we benefit from it. Novatek did well, and we also benefitted from the ramp up of Termokarstovoye, where we are also a direct equity partner. On top of that, I would remind you that our equity affiliates and LNG volumes have increased by 15% compared to the second quarter 2015. This may be part of the explanation also.

Thank you. We'll now move to our next question which comes from Oswald Clint of Bernstein. Please go ahead, your line is open.

Just in the context of your cost reduction progress, I wanted to maybe get you to talk about your unit upstream -- or production cost per barrel, the kind of unit metric that was indicated to fall quite a bit this year, to the mid sixes, $6.00 or $6.50 a barrel. Could you say if that number is being achieved already through 2016? And then secondly, just on -- obviously you've signed quite a few LNG contracts this year, and mostly long term into Asia, which is telling us about long term demand. But you could you talk about the inherent -- just generally about the type of pricing within those three contracts, please? Thank you.

Your first question about the upstream technical cost, if you use the standard definition, the ASC-932 OpEx definition, which we use for the purpose of communication, we have already reduced this upstream OpEx to below $6.50 per barrel, which was initially our target for the full year. We did it already. This is done. We continue and improve the efficiency of the operation, and we continue to optimize the supply chain. Just an example, for instance we have negotiated a 55% reduction on our rig contract in Congo in exchange of an extension. This is part of the overall process for us to reduce costs. LNG contracts; I hope you don't ask for me to give you the numbers and the exact formula because, honestly and first of all, I am not a specialist. Second, even if I have the number in front of me I'm not going to give it to you. These are highly confidential data. We signed three long term agreements this year to deliver a combined of around two million tons a year of LNG to Pertamina in Indonesia, ENN in China, and Chugoku Electric in Japan. I'd like to point out that the agreement with Pertamina demonstrates the added value of a global portfolio. We agreed to take Pertamina contracted volume in the U.S. and supply more volumes in Indonesia from our own LNG portfolio, so providing basically option to our traders as well as creating a net seller position. We are currently slightly, I would say very slightly, long in LNG. The agreements with ENN and Chugoku Electric are traditional long term sales agreements, 10 years for the Chinese and 17 years for the Japanese. And both are the traditional agreements we have in Asia. And I am sorry, but I am not going to give you the exact parameter. We are well positioned along the entire LNG value chain. Beyond these contracts in Asia, we also have strong marketing portfolios that add margin and resilience. And we plan to continue and grow this segment as illustrated, for instance by a small acquisition, yes, but with the Lampiris acquisition, which is a marketer for gas and power in Belgium.

Our next question comes from Nitin Sharma of J.P. Morgan. Please go ahead.

One question, please, if I may. If I look at the H1 operating cash flow of $7.7 billion, that's excluding the working capital changes. Now, could you help us draw a bridge between $40, $7.7 billion in H1 versus what is required in 2017, $22 billion to $23 billion at $60 annualized? Maybe some comments on key moving parts, contributors that will improve the operating cash flow run rate from H1, please?

You know our sensitivity by which $10 per barrel provides about $2 billion a year of cash. This sensitivity seems to be slightly under valuating the current sensitivity. We are making a computation currently because it might be that, by lowering our break-even today, the sensitivity when we are close to the $40 per barrel may be slightly higher, I don't know, maybe $2.2 billion for $10 per barrel. And I think with that you have the math for the future. Of course, we will update you in September, but basically our sensitivity is slightly increasing at the moment. We repeat at that stage that next year at $60 we will pay a full cash dividend. This is -- this was and this is our goal, and this is our objective.

Thank you. Our next question comes from Bertrand Hodee of Kepler Cheuvreux. Please go ahead.

Two questions, if I may, so first on the refining environment. So, H1 was pretty good at $35 per ton, bang in line with your budget. Refining margin has come down. Can you give us a flavor of where the -- of where your refining margin indicator stands right now, and where do you see it going forward for the next couple of quarters? That's the first question. The second question is on a potential next FID. I noted that you mentioned Angola in the potential next wave. Is [Xenia] or other opportunities could be sanctioned near term?

So, it is true that first half this year we had a European refining margin at $35 per ton. And this enabled us, with petrochem sector, to provide strong results. The environment is volatile at the moment. I can't be too specific because I may be wrong. Currently the margin, yesterday I think, was at $20.00 per ton, but what does that mean for one day? I don't know. It is obvious for us that product inventories are high on the market at the moment, which does not help so much the refining margin to recover. Your question about Angola, you were right. You can do my job. This was Xenia.

Okay. And as a follow up, do you believe that now the costs are right at Xenia to be able to -- for Total to launch a project?

We haven't yet seen the result of the cost estimates, so I can't answer you.

Thank you. We will now take our next question from Thomas Adolff of Credit Suisse. Please go ahead.

Patrick, thank you. Two questions, please, one on disposals and actually on [EXXIS]. Your disposal plan amounts to 10 billion, and I remember very well when you announced it. That excluded the special chemicals business including Atotech, despite the non-core nature of those businesses. And you also said in 2016 or for 2016 that the plan is to sell $4 billion worth of assets. Now you're now including Atotech. So, the question I have here is whether Atotech is part of the 4 billion or it adds to whatever you might get for it. And if it's really part of the 4 billion, basically it means something else is not working according to plan. The second question on EXXIS, just wanted to get a better sense for when first oil would be if you miss the weather window. And actually staying in the spirit of EXXIS, I recall a year ago on EXXIS everything was fine. And I think it was fine up to 85% completion, and things went less according to plan. Now, if we look at Yamal, if I'm not mistaken train one on Yamal is 66% complete. What is the level of confidence on the target on Yamal and how would you compare it to EXXIS and the risk factor around these projects? Thank you.

Thomas, you need to meet our project manager. I am not sure I am able to answer your question. You gave several numbers about asset sales, but you missed the most important one. The most important one was an overall yearly target of $2 billion net of acquisitions, which is the main objective we follow. Nevertheless, it is true that the oil price environment is not favorable to sell upstream assets, and we are not desperate to sell assets at any price. We have a few projects under negotiation at the moment to sell midstream assets, mostly pipeline infrastructure. And the market is there for those assets. So, be patient and you will see what we will be able to sell by end of this year. Honestly, I feel comfortable with our target of $2 billion net. And the $10 billion overall target, I am not anxious about it also thanks to these assets in the midstream sector. EXXIS and Yamal, so I need to change my cap and be a project manager. Let's move to EXXIS. The overall project progress at end of May this year was 89%. The operator, namely Impex, is aiming for startup in the second half of 2017. According information I have, drilling performance has accelerated recently, and one of two rigs was demobilized in June. Wells are testing in line with expectations. The construction of the CPS and ESP is still progressing in Korea. And onshore, the overall progress is 90% as May 2016. And the pipeline at MIU was completed. So, as of today I stick on operator startup objective, which is second half of 2017. That is the operator target, and I don't have better target than that one. Yamal, it's a different project. Drilling is simple. Building an LNG plant is simple. The only difficulty is the temperature we face in this area of the world. But the progress is good on Yamal. As of June 2016, train one was 73% completed. Another thing which is important for everybody is that we complete the financing of this project. We have been able to raise more than $18 billion from Russian and Chinese banks, and the first rollout [Technical Difficulty] was two tranches. Just to give you an idea on the size, there are currently 16,000 people working. And long lead items for train one and train two, which are mainly compressor or turbine, have been delivered on site, along with the heat [HNJ] built by General Electric. More than 95% of the LNG is committed. That's the marketing side of the project. More than 95% of this LNG is already sold to the market. So, honestly, I don't know if you have an opportunity to visit this part of the world, but the progress of this project is very impressive. And I am extremely confident in the ability of the Russians to complete their project in due time.

Thank you. We will now take our next question from Lydia Rainforth of Barclays. Please go ahead.

Thanks, Patrick, and hello. If I could, just one question on the cost savings and the idea that you're going to surpass the $2.4 billion target for this year, is that a reflection of you're just getting more done quicker, or are you actually getting more savings on the things that you are trying to do? Thank you.

Yes, we gave the information to the market that our initial target of $2.4 billion for this year, we will do better. Is this coming from the overall deflation or is this coming from our own job? Honestly I don't know and I would say -- sorry to say that this way, I don't care so much. What I actually see is that the costs are going down and that we are able to capture what is given by the market, and potentially to do more than that. What I can say is that those gains are sustainable. This is not coming and elapsing in a few months time. Those are sustainable gains.

Thank you. We will now take our next question from Kim Fustier of HSBC. Please go ahead.

Patrick. I have two questions, please. Firstly, I was hoping you could talk briefly about Total's intentions in Iran, as the government is reportedly close to agreeing in fiscal terms on your projects. The second question is on downstream gas. And Total has said it's ready to go as far downstream as it takes to unlock gas demand. Could you possibly share any thoughts on how much of these efforts will target access to existing gas demand, like the Lampiris deal in Belgium, for instance, versus creating new gas demand on the other hand? Thank you.

With our plan in Iran, we are currently lifting 150,000 to 200,000 barrels per day of Iranian oil from our trading operation. And basically this oil is going to supply our refineries in Europe. We have signed a memorandum of understanding with NIOC to allow us to access technical data on certain projects, and another MOU with the Iran National Petrochemical Company to jointly study [Ali-Tain's] steam cracker. So, we are not only working on upstream side, but also on the downstream in the petrochemicals. You know that we know well Iran. Total was one of the first international oil companies to work in Iran in the 1990s, and we have obviously the technical expertise needed to help Iran developing its resources. The most important element for us is the profitability story of the Iranian contracts. We know that investing in Iran has some risk, and we will do only if we have the appropriate reward, so a good level of profit. And there is no reason that we could not achieve that, because there is a common interest between Iran and Total. That's for Iran. Then you have a question on downstream. We are willing to grow our downstream presence in gas because it provides outlet for our production and adds margin as well as resilience. We have been active in the B2B segment in Europe since the beginning of our operations, and this is part of our gas trading and marketing business. And Lampiris now will help us to grow in the B2C segment. So, we were in the B2B and then we are now moving into the B2C, the overall objective being to find outlets for our gas production. And this gas business, which is very important, will be part of the new gas, renewables, and power division, led by Philippe Sauquet, as he will be appointed first of September. And Philippe will be part of our presentation in September, so you will have the opportunity to ask him questions about it.

Thank you. As there are no further questions, I would now like to turn the call back to your speaker for any additional or closing remarks.

Thank you, everyone, for joining us today. As you saw, we are the one delivering some results. To close the call, I would like to leave you with the following. We are delivering across a wide range of ambitious objectives, including production growth, cost reductions, portfolio management, and the reorganization. We are preparing Total for the next decade by lowering our break-even and maintaining strict investment discipline and project selection. And I am extremely confident that Total will continue to perform competitively regardless of the environment. And I have to say that today I am quite proud to work with Total, able to deliver such state of results. I look forward to seeing you -- all of you in September at our London Investor Day. And please take some time off and relax. My car is waiting for me.

Thank you. That will conclude today's conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.