Welcome to the Royal Dutch Shell's 2016 Q3 Results Announcement. There will be a presentation followed by a Q&A session. I would now like to introduce the first speaker, Mr. Ben van Beurden.

Thank you very much, operator. Sorry to disappoint the audience. It's Simon Henry, CFO. Ben is not with us today. So, ladies and gentlemen, welcome to today's presentation where we've announced our third quarter results this morning. Hopefully you've had a chance to review, and I'll begin with the summary, and of course there will be plenty of time for questions. I am also joined, I should note, now by Maarten Wetselaar, Director of Integrated Gas and New Energies. Maarten will join for the Q&A session. We have a prompter slide for you, prompt you for your questions. But we thought it'd be useful have business directors join me on these calls from time to time. So before we start, just let me highlight the disclaimer statement. Shell delivered better results this quarter, reflecting strong underlying operational and cost performance. But lower oil prices continue to be a significant challenge across the business, and the outlook does remain uncertain. We delivered some $3 billion of underlying CCS, current cost of supply earnings in the quarter, $7 billion over the last 12 months. The integration of Shell and BG is now essentially done. It's been completed well ahead of plan. It's worth a reminder it's essentially 19 months since we announced this deal. We've spent 10 months completing it, 40 major regulatory approvals, no value given away, nine months on integration, all the value now embedded in plans. The integration is proving a very important catalyst now though, as we make significant and lasting changes to the combined companies' working practices, to our cost structures, and of course overall to the portfolio. Our underlying operational cost in 2016 are already at an annualized run rate of $40 billion. That's a quarter ahead of when we suggested we would achieve this, which…

Thank you, sir. We will now begin the question-and-answer session. We will now take our first question from Oswald Clint from Bernstein. Please go ahead.

Thank you very much. Yes. Maybe one question each, please. Simon, just on the gearing number, the 29%, I think you've guided it pretty well the last six months or so, saying it should trend up for the short term, which it has. But as you look at these numbers today and your CapEx guidance and your trajectory back towards the 20%, is that something you feel is certainly on the cards as we enter 2017? Is that a kind of gearing number we should think about as maybe by the end of 2017? Please, that would be the first question. And since Maarten's here, I'd like to ask him about the Singapore LNG contract that you've just announced. And I'm curious, is this more of your short-term gas in your portfolio or your short-term gas you're allocating to Singapore, and is that happening at certainly a better price in terms of our modeling? And also, I noticed that the – there's been a new 0.5% sulfur cap on maritime fuels last week announced by 2020. Is that kind of feeding into your aspirations for LNG into transportation? Is that something we should pay particular attention to, Maarten, please? Thank you.

Oswald, thanks. I'll leave the second question to Maarten. There's a great story there, particularly on your second point on sulfur and marine. 29% gearing, indeed we've guided well. If I just step back a year, we were talking about gearing in the mid-20%s post-BG. So, what was changed since then, well, a couple of things. One is that the oil prices stayed lower. That's probably cost us several percentage points, probably 3-plus. The divestments are being slightly slower. That's probably cost us another 1 percentage point. But importantly, you will have picked up hopefully that the finance leases that we have recognized will have added to the gearing. These were operating leases in the BG book, and we've actually added further finance leases both in Brazil and in the Gulf of Mexico since we completed the acquisition. And the total effect of the leases has added 2 percentage points to the gearing. On the flipside, our overall performance has been better and we've delivered much lower cost. So that's helped the gearing. But overall, we're around 4 percentage points higher, but two of those don't really count on the grounds that it's just an accounting change. And slightly better off in that sense than one would hope for. How do we feel for end 2017? Well certainly end 2016, it could go slightly up or slightly down in Q4, it will depend a little bit on divestments in oil price. But perhaps just to wind back to the CFFO, the cash flow statement, and tell you how these numbers field through to us. The third quarter was good cash generation, but it's never really insightful to look at a single quarter for cash generation. So, if we look at a 12 months, let's go back 12 months, 8 months…

Mr. Wetselaar, please ensure your mute function is turned off. Thank you.

Let me cover that question then. Singapore...

Simon, can you hear me? I'm trying to speak into the phone but is it working now?

Please.

Simon?

Yes. Maarten, go ahead, please.

Yeah. Sorry, I am – I appear to have lost the line for a moment and then someone else. Yeah, we're very pleased to get the Singapore license awarded. We inherited from the BG, of course, a 3-million-tonne exclusive license that was almost full in the sense that they had contracted 2.7 million tonnes. And these are rights to contract long-term volumes, so we've now been able to add to that another 1-million-tonne long-term tranche into Singapore. So in terms of we'll be selling 4 million tonnes of LNG long term into Singapore and so this will grow – this will come from our portfolio but it will reduce our near-term and long-term length by another million tonne of premium market access. So we're very pleased it. But it's not necessarily we only profit at short-term volume, the volumes will be well into the 20s and early 30s. And interestingly in this case, we are able to serve our own demand. We have 0.7 million tonnes of LNG demand with the Bukom refinery and the Jurong chemicals complex that we're now able as of 2018 to serve through the Shell network and integrate the whole value chain. On the transport, indeed we've been focused on LNG to transport. That's a very important new sector for LNG to serve going forward because the heavy transport can't electrify, so gas is quite likely the kind of destination energy source for heavy transport. And if you convert the current shipping markets to LNG in its totality, you would find about 250 million tonnes of extra LNG demand, and on the onshore heavy trucking and long-distance market, it would be about 500 million tonnes. So that put together would be 3 times the current global energy supply. So very, very important and material sector…

Many thanks. It's a great story. We'll take the next question.

Our next question comes from Thomas Adolff from Credit Suisse. Please go ahead. Thomas Adolff - Credit Suisse Securities (Europe) Ltd.: Afternoon, guys. Two questions from me as well. One for Simon and one for Maarten. Let me begin with Simon. Maybe if we talk about – if we look at your priorities for cash, you've mentioned that debt reduction is a top priority. Perhaps, if I put it differently, is maintaining the A credit rating status more important than preserving the dividend? That's my question for Simon. And for Maarten, I think you talked about or you've given some unrisked figures in terms of upside from LNG to transport, et cetera. But if you had to give a risk figure for the IMO-related demand growth to say 2025 in addition to a risked figure for FSRU-related demand growth to 2025, what would that be for the LNG market? Thank you very much.

Thanks, Thomas. Again, I'll obviously still leave the LNG for Maarten. Priority number one is debt reduction. We need to bring the debt down. The question between credit rating and dividend is one and I hope not to have to face in practice. At the moment, as I hopefully just indicated, it's tight and its close and it does require the oil price to stay roughly around $50. But we should be able to manage reasonably well through the next 12 months. It is clearly important – the debt reduction is a proxy for maintaining the credit rating. The credit rating is very important. I think we could effectively survive one notch further. And we're AA with one rating agency and A with the other, so three notches difference. So we could survive some level of downgrade as long as it was clear how we were going to get those ratings back. And the best way of getting the ratings back is fundamentally to work on the numerator of all the ratios, so take cost out, keep it out, and deliver those new projects. So each quarter, we see a little bit more of that. But clearly, it's the divestments that reduce the denominator, the debt, in the short term. And I think we have to do both to ensure that we keep both the debt markets and the equity markets happy and comfortable. And I'm really quietly confident that the underlying performance of the portfolio is moving into a position where we can achieve that. Maarten?

Yeah. Thanks, Simon. If I start with LNG to transport and that's the one with the biggest range of uncertainty, but that range has probably crept up this week with the IMO announcement. The range I would use for the 2025 volumes something in the range of 35 million to 60 million tonnes of LNG to go into transport. That does include road which isn't affected by IMO. The IMO is only for ships, but LNG for road transport is also ramping up over the period. It would end into 2030s – it could well potentially break 100 million tonnes before the end of the decade if growth indeed continues. And this partly depends on infrastructure being built of course. If you then look at the rest of the LNG market, we see it grow between 150 million and 170 million tonnes between now and 2025. And your question was about FSRUs and there's, of course, also market growth into onshore terminals that are not floating regas units, but basically countries like China, India, but also Europe where basically – where FSRU is used but larger tanks in the imports. The shift – it's probably about a third FSRUs, two-thirds bigger onshore import facilities, if I got your question correct. The FSRUs are predominantly Africa, Latin America, Middle East, and Southeast Asia, on-land infrastructure, very much built into China, into Europe and to some extent, in India as a bit of a mix. So, that's what the import picture looks like. So you'd be looking at a range of about 424 million – 420 million tonnes in the high end of 440 million, 450 million depending on exactly how fast the transport business indeed grows, all by 2025.

Let's take the next question, please.

Our next question comes from Theepan Jothilingam from Exane BNP Paribas. Please go ahead.

Yeah. Afternoon, gents. Three questions, please. Firstly, Simon, could you just talk about the scenario then beyond paying down debt, how we should think about the group turning off the strip? So what type of debt metrics should the market look for, or is there a signal on the oil price at a particular level where you think the Scrip can be removed because it is arguably dilutable increasing that dividend burden in the long term? Second question is relatively vanilla. Just could you give us an update on Prelude and start-up and what remains to be done in terms of commissioning? Thank you.

Many thanks, Theepan. It's quite handy having Maarten available. I'll pass Prelude to you because it is your project, Maarten, but not too many details, please. Scenario beyond the debt reduction, a key trigger, you will feel and we will feel comfortable that the financial framework is rebalancing in our favor, will be to turn off the Scrip dividend. Fully agree with you that the dilution and the additional dividend are not something we want to live with forever and would like to address as soon as possible. It's a combination of two factors, likely, Theepan. First, we actually have to get the metrics moving in the right direction. The debt must be coming down. But it must be doing it in a sustainable way, so that we don't take the Scrip off and six months later find ourselves having to put it back on again or feeling that was the prudent thing to do. So I've said before, we need to have line of sight to gearing of 20%. That, to be honest, is just a good proxy for the overall rating metrics, and indeed where the oil price settles out will be important. Now, for the next 12 months, we see the oil market by and large imbalanced in terms of supply and demand. Thereafter, it's likely that demand if it continues as it is will outstrip supply. And where the oil price settles out in that period will be a factor, no question. But before then, I think we need not only to deliver, if you like, the organic cash balance that I talked about, getting the cash generation up into the low-30s, but we need to deliver some divestment, and that will start to turn the metrics. But really you need the net debt heading down more towards $50 billion, than running into 70s, before we would look at the Scrip. But it's really about being confident in the sustainability and not just one offsetting numbers. And, Maarten, Prelude.

Yeah. Thanks, Simon and Theepan, of course. I was recently on Prelude to review progress. We've been busy steam blowing in the third quarter. That's getting close to being finalized. So, we're really into a period now where the major construction work is over, and we're into starting commissioning, handing over to operations and working things up. So Prelude progress is solid. It is as per our plan, which means that the message about getting substantial cash flow from Prelude in 2018 is still very much on and increasingly looking derisked as we progress this project. So going well and looking forward to cash in 2018.

Great. Thanks, Maarten. To the next question, please.

Our next question comes from Jon Rigby from UBS. Please go ahead.

Yeah. Thank you. Two questions. First is the quarter – this quarter looks – resembles much more like quarter at the current macro that I'd expect Shell to deliver. 2Q didn't, and I know with 2Q it was a bit of backwards and forwards about why it was such an odd quarter. And I just wondered whether with the bit of time after the second quarter and also reviewing the third quarter results, whether there's any more insights into that delta 1Q to 2Q, 2Q now to 3Q that you can share with us and maybe sort of confirm that the third quarter, as you would see it, is much more resembling the financial and operating performance of the underlying business, if that were possible. The second question is just on the Downstream. The Marketing result looks a very, very strong result. If I look back against history, when you have disclosed those numbers, it looks right at the top end. And yet, if I look at the macro, it's not obvious that it was a quarter where Marketing should do fantastically well. There wasn't – we didn't see a huge drop in oil prices. It wasn't obvious that demand was going very strongly. So I just wondered are you able to share something about why Marketing was such a standout result in the quarter. Thanks.

Sure. Thanks, Jon. Important question in the first one. Certainly, it was not easy to explain Q2 because there were quite a lot of small factors that in and of themselves were a bit one-off. And some of them have reversed this quarter as well. So I'd say about $400 million has come back into the third quarter, most of which, if not all of which, was in the Upstream results. In fact, Maarten's got $100 million negative Upstream, probably got close to $500 million positive. I talked about the adjustment to the PPA or the purchase price allocation, premium allocation from the BG acquisition. So, there's been a true-up of depreciation and actually in practice a reduction of that step-up on the PPA but we previously talked about $300 million a quarter. I think going forward, that step-up will be more like $200 million a quarter although it will grow over time as the production continues to increase. And then, there's a couple of tax items which also either reversed or a one-off in the third quarter. So, Q2 underlying understated to an extent; Q3 slightly, overstated. Q3 is more representative although I would note that refining margins in downstream were particularly weak, and the chemicals still have more earnings and cash generation power when all the crackers are running. So, there is, clearly, in the fourth quarter, what we would be watching is, one, the oil price; two, that the costs come out and stay out sustainably; and three, that the new projects, at least all the ones I sort of talked about, Gorgon, Stones, Kashagan, two FPSOs in Brazil, they didn't actually contribute a lot to the third quarter financials, they should all contribute more to the fourth quarter financials. So, an uptick of revenue generation, continuing…

Next question is from Rob West from Redburn. Please go ahead. Rob West - Redburn (Europe) Ltd.: Thank you very much. I'd like to ask my first one on the GoM, I think there's a couple of wells in the Southwest part of your Norphlet acreage, Leesburg, Castle Valley, one I think was Dover. Is there any updates on that this quarter? And just looking back at the well you announced last quarter, is that something that could become a hub around the Southwest of that position or does this stuff all just tie back to Appomattox? That's the first question. The second one is just – maybe for Maarten, maybe for whoever of you prefers it, so I was just a bit interested if you can say anything about the onerous contract provision you took in LNG and a bit of what's behind that. Thank you.

Many thanks, Rob. I'll handle the GoM. I think the onerous contract really is gas tolling into Spain. So, Maarten, can you cover that?

Yep, yep.

But on the GoM, you're right. The Norphlet play is in the Eastern Gulf of Mexico and we were the first in there. And we're effectively partnered with Nexen, but there aren't many other people in the region. The Appo discovery keeps growing, both from nearby discoveries and itself. We took the FID on Appomattox last year. We have seen the original breakeven price around $55. We've continued to take costs out. So that breakeven price is – now starts with a $4, and we're continuing to look for further opportunity. And one of the things that's helping is greater volumes. You're right that Rydberg last quarter was a success, that we are now drilling in Castle Valley, and I'm not sure about Leesburg at the moment. But we are effectively not announcing anything there at the moment. We have used the early-mover advantage to take further acreage in the region. And is it a hub region? Well, absolutely. Once Appo is up and running, we're talking of 220,000 barrels, 230,000 barrels a day. But we are already looking at whether and how we could debottleneck because it is quite clear that the discoveries we already have will keep that full for quite a lot of years, and there is still further potential. So it will be at least one hub, one pipeline back into the Gulf Coast. So it's looking like a great opportunity and, on average, we're something close to 80% of the holding in the acreage with most of the rest being – in fact, nearly all the rest being held by Nexen. So it's a good partnership, great prospects. The hub development already in play to two to three years before it produces, but it will be one of the major, major cash generators for Shell into the 2020s. Maarten, onerous contract?

Yeah. I think that's a contract that was from the middle of the last decade for 2005, a tolling deal in Spain, the type of which we haven't really done since then. We had a few tolling deals in the state as well in that period. None of them worked out very well. This deal particularly has been underwater for most of its duration. We only now have 4 years to go and there were no plausible price scenarios anymore where this contract would ever get back into the money and therefore we wrote it off as a – the last four years wrote it off as an onerous contract. You can't do that too early in the life of a contract although even 4 years ago, we didn't have much hope with our rules around how far in advanced you can recognize this given that markets are volatile. But this one was so far out of the money that we were able to take it out of the books and forget about it.

Thank you, Maarten. Move to the next question please.

Our next question is from Irene Himona from Société Générale. Please go ahead. Irene Himona - Société Générale SA (Broker): Thank you. Good afternoon, Simon. Two questions. First, on the cash flow. So capital expenditure in the nine months is shown at around $16.4 billion. You're guiding today to effectively $26 billion cash CapEx for 2016. Are we looking at $9 billion to $10 billion for the fourth quarter CapEx? And related to that, your DD&A guidance for this year, $22 billion, could you kindly give us some guidance, some sense of what happens to DD&A next year, please? And my second question just on Brazil where obviously, they've changed the legislation recently to relax the requirement for Petrobras to operate everything in the pre-salt. How's Shell strategically thinking about this opportunity, please? Thank you.

Irene, thank you. On the capital investment, I have to say, we've focused more on 2017, 2018, 2019 than we have been doing on the next three months because that tends to be locked in. And maybe at $29 billion, it's a little bit rich, but that's not going to drive the metrics too much one way or the other. We do have couple of one-off items in the fourth quarter including the payment to enter the chemicals development in Guangdong province to CNOOC in China. And we have additional FPSO coming on in Brazil. So let's see how it turns out. I would regard $29 billion as a maximum. DD&A of $22 billion for this year, that will be how it starts next year. But I think over the year, as we see the following come on stream and ramp up, it will increase. We will see Kashagan kick in for a full year. We will see Gorgon Train 2, Train 3 hopefully come on stream. We will see Schiehallion and we will likely see some of the tiebacks in the Gulf and a ramp-up in activity in the Permian. So I would expect all of those to drive depreciation up, but it will then be driven down by proved reserves bookings at the end of 2016. I don't yet have a fix on that simply because we don't do the work in detail until basically November, December. So, over the next quarter, we will get a fix on the DD&A. But the figures I gave earlier on the cash flow are not impacted by DD&A, but obviously, the earnings that go with them would be. And hopefully that helps. In Brazil, it's early days really. And indeed, there have been statements about changes in requirement on operatorship, the…

Our next question comes from Guy Baber from Simmons. Please go ahead. Guy Allen Baber - Simmons & Company International: Thanks very much. You're giving clarity on 2017 CapEx a little bit earlier than normal of which we very much appreciate. But relative to that prior range of $25 billion to $30 billion, can you just discuss the rationale behind the decision to guide to $25 billion at this point? Is it reflective of efficiency capture, meaning the low end accomplishes pretty much everything that you wanted to accomplish before? And I'm just curious how fluid that guidance is at this point in time to better understand the commodity price assumptions and under what pricing scenarios you might flex that higher or lower? And then I have a follow-up.

Thanks, Guy. Good spot, this is at least three months earlier than we would normally communicate next year's capital investment. Now, to an extent, it's slightly easier than it normally is because the reason it is going down from this year is we actually finished projects. I won't repeat the list of projects that I've just stated but we stopped spending on those projects. And we're not taking significant new investment decisions. I mentioned Appomattox earlier. We're investing in chemicals both in Pennsylvania and China. We continue to finish off obviously Prelude and we're investing in subsea activities whether it's Nigeria, Gulf of Mexico or the North Sea. So there's still quite a lot going on. And we gave a range of $25 billion to $30 billion as being bookends that were not necessarily associated with the top and bottom of the price cycle. But in terms of affordability, obviously, they are. $25 billion would seem to be a soft floor. So if we have to, we can drop below and $30 billion is a hard ceiling. We will not go above $30 billion even if we have the cash until we have embarked on the buyback program which is postscript and certainly when we're in a better financial framework overall. So we're several years away from that. So that's whey what we stated on the range. Why $25 billion now? We are coming off very significant investment. Our priorities are reduce the debt. And therefore, it's appropriate but we don't have to jump into new investments that we focus on maximizing the value from the investment we've just been making. Can we go lower? Is it flexible? To an extent, yes. And lower oil prices would drive that. So it would be driven by affordability in the short term…

We will take the next question from Lydia Rainforth from Barclays. Please go ahead.

Thanks. And I just had one question actually, please. Coming back to the OpEx numbers and the underlying cost already being at the $40 billion run rate that you talked about back in June, what has actually driven that? Can you give us some examples of where the costs have come down and just any indication in terms of how much further they could go? Also, when we might see that coming through? Thanks, Simon.

Yeah. We'll do. Thanks, Lydia. Interesting tables at the back end of our results announcement on pages 21, 22, and 23 gives bit more detail around things like returns, divestments, CapEx, gearing, and operating expenses. What we've done is actually split out off the face of the P&L statement the total operating expense, which, this quarter, was almost $10 billion exactly, and therefore, $40 billion run rate, but also adjusted for the one-off items that we effectively include in indentified items in the earnings statement. So that you can actually see underlying operating expense $9.2 billion in Q3 and is $28.5 billion for the year-to-date. And that includes eight months of BG, and that compares with nine months last year $29 billion not including BG, hence, the comments I made earlier. Where does it come from? Well, pretty much everywhere, I have to say. If we look at our costs above the asset – so think finance, IT, HR, legal – we've taken out, if we look 2015 through to 2017, something like 25%. That's been done partly by delivering the synergies from the deal. We don't need to do certain things twice. But it's been done through doing things differently, fundamentally simplification, offshoring of work to centers in Chennai, Bangalore, Manila, Krakow, and simply by doing things simply. On the assets, we have had quite significant programs in the upstream around operational excellence that are focused on better availability, effectively managing the wells, the facilities, and the reservoir in a more farsighted manner and one that sort of builds in the cost over a period of time and that is actually driving unit cost down in particular. And I think there is – it is bit of an intangible, but bringing the BG guys into Shell, there's always a…

Our next question, from Lucas Herrmann from Deutsche Bank. Please go ahead.

Simon, hi, and Maarten, afternoon. A couple if I might. Simon, you've mentioned the Permian two or three times on this call. I think Ben describe them the sleeping beauties, but it sounds as though it's time to wake up. Can you talk a little bit more around the way you may be thinking about that acreage plans, rigs activity, et cetera at this moment in time? Secondly, I wondered if you could give us a little more flavor on the 2016 $500 million-plus divestments that are ongoing. Just flavor in terms to what extent or how near or far some of those may, may not be to actually hitting the headlines, for want of a better phrase. And finally, I've got to ask this. South America, Brazil, if I look at the regional profit performance, I have seen $700 million net income turnaround in that business. I wonder if you could provide some explanation. I know barrels are up, but the profit improvement is dramatic.

Sure. Simply to answer on the last question, I think, Lucas, is some of those one-off reversals that I mentioned earlier relate to depreciation in Brazil. So it's something around $200 million, $250 million positive in Q3 that was negative in Q1, Q2. There's a bit of tax exemptions as well, plus more barrels, lower cost, so that...

Okay.

...probably is the big driver. At Permian, what will we do? We have 300,000-odd acres. We bought most from Chesapeake sometime ago. It's great acreage. We're in some of the sweet spot. And to date, we've been investing somewhere between $500 million and $1 billion a year. But it's been on appraising rather than producing. I think it's fair to say, what we – a lot of that acreage is in joint venture with Anadarko. We are operating four rigs at the moment, likely to go up to five. Anadarko is operating similar. That we are certainly from a Shell perspective in our operating acreage, we are now looking at moving to what we call the harvest phase. We know what we have, now we start to harvest some value. Well, just over half of our Permian acreage, we believe has breakeven price below $40. We have 2,500 locations that we've already identified that should work at below $50 and there are three particular what we call common value areas that we are now looking to develop. And we will start developing those – and this is real genuine pad drilling, move into the manufacturing approach as opposed to drilling one or two wells in a section and moving on once you know what you have. So you move on to 10, 15 maybe more wells per pad, multiple horizons, et cetera. So it's actually exciting as we look forward. It's good acreage and we want to be part of developing that. We've also recently re-contracted some of our evacuation infrastructure and half the pipeline cost going out for us, which is one of the reasons we've not developed it previously as well. So we're in a pretty good place in the Permian. Sometimes, you'd like a bit more. Sometimes,…

Our next question is from Iain Reid from Macquarie. Please go ahead. Iain Reid - Macquarie Capital (Europe) Ltd.: Yeah. Hi, Simon, Maarten. First question for you, Simon. You probably saw what Exxon said on Friday about looking at their reserves. They did a kind of pre-release of this. I know you said you're going to be doing it at the end of the year, but appreciate a comment if you could. They basically said they're going to de-book oil sands due to current environment. Now, you've got a pretty similar asset there, so I'd be interested to get your view on that. And question on Maarten, U.S. LNG, now you seem to be saying that it's not going to Europe at the moment, but you've got other areas where it's more profitable to take it, I presume. When we get the big volumes coming, it's going to have to go to Europe. I was just wondering what your outlook is for European gas prices, when that starts to happen?

Iain, thanks. Obviously I'll leave the second question to Maarten. On reserves, indeed we look at these in November, December. I won't comment on competitors directly, but oil sands mining, we have obviously the Athabasca Oil Sands Project of two mines. There's 1.94 billion barrels of oil in proved reserves today and $100 million or so of positive earnings and roughly that amount is slightly less in positive free cash flow in the third quarter earnings. So at $46 oil sands is both earnings positive and, importantly, free cash flow positive. I say importantly because the challenge with reserves in a low-priced environment is the need to pass the economic limit test. You need enough reserves to be able to show a positive forward cash flow. And that's probably all I can say is if we're positive at $46 we should just about be okay I would have thought at whatever the average price for the year turns out to be. Elsewhere in the portfolio, low prices could possibly have an impact. But, of course, it would not necessary make much difference to the operation or the value embedded because it merely is a mechanical spreadsheet extrapolation of a historic price based on approved volume number only, which may not be anything like the total resource associated with an asset and the current balance sheet. So it's basically into a sausage machine. And I can't comment either way until we've done the work. But oil sands interestingly looks reasonably positive. Maarten, on U.S. LNG.

Yeah. Thanks, Simon. And thanks, Iain, for that question. Indeed, in the early days of U.S. LNG, the best way to deal with those [cargos] has been to keep them in the Americas and send them to Chile or Brazil. And that's where the sort of our allotments have been ending up. But you're right to say asset production volume ramps up, there won't be enough demand in Latin America necessarily to absorb it all. And it's going to go – it's going to have to go somewhere. Just a long-term comment and then a short term comment. The long term, the way I see prices moving in the kind of medium term is that a recovery in oil price is going to drive initially most of the Asian prices up, simply because a lot of the Asian businesses is oil-linked and that will jack prices in the Asian Pacific basin up. Also, that's where most demand growth will sit. And then Europe will kind of sit in between depending a little bit on whether, on the balance in the market on the moment in time whether it will more follow Asia or whether it will sit at the kind of U.S. surplus rate differential. In the near term, what we've been seeing is two things. It's actually price spreads widening. So at the moment, we see Henry Hub starts at $3, European gas price is back to about $6. And we're selling LNG spot in the Asia Pacific at $7 again. So these are prices where certainly the way our Sabine Pass contract is established, where we would be able to send the volumes either into Asia or into Europe and make a margin. The demand trends that Simon highlighted on the slide he showed on the LNG market are quite profound. You saw the Middle East grow by 8 million tonnes. That is from a total of 8 million tonnes last year in the first nine of the months, so that's a doubling of the market. And we've just had Egypt announce a tender for 96 cargos for 2017-2018. 96 cargos, that's about say, 6 million tonnes of LNG and we see similar numbers – or similarly, large tenders coming out of India and other places by new customers. So I think in the near term, there is more opportunistic demand, partly driven by lower prices that I think will attract LNG from the U.S. But clearly, the lower price contracts, we have the best one in the business through Sabine Pass ex-BG will be the ones to benefit first. In a very negative outcome, you could see the higher-priced contracts running into a place where they don't actually operate at all. But as I say, I rate that as a lower probability and certainly we are not in those contracts.

Thank you, Maarten. Let's take the next question, please.

Our next question comes from Christopher Kuplent from Bank of America. Please go ahead.

Hello. Thanks. I'm going to keep it very short. Simon, I know this sounds like Groundhog Day, me asking the same question on every call. But given that we've seen Total again in the market issuing hybrid bonds with coupons near 3%, wanted to test yet again your appetite for doing the same. We just talked about protecting your single-A credit rating, et cetera, how attractive do you think is that route relative to asset disposals or indeed accepting another notch-downgrade to A minus? Thank you.

Thanks, Chris. My memory is good enough to remember, as always you, so you're off the hook. Hybrid bonds, we go to market and we get very tight pricing even with the lower credit ratings that we've been achieving with S&P. Hybrid bonds are not cheap financing. They might contribute to the rating, but they are expensive. And the carrying cost is as expensive as is discounting your dividend. We do not need to do that. If I needed to do that, then maybe we'd think about it. But we don't need to do that. I will continue to stay plain vanilla in the capital market – the debt capital market for as long as that is by the far the cheapest and easiest available source of debt to me. And it's really probably the same answer I gave last time, Chris. It's relatively low quality source of finance and not cheap. And just for avoidance of doubt with everybody, I do understand that nor is equity issued through scrip, hence the earlier comment about high priority, reduce the debt so that we can take the scrip off. So thanks, Chris. I'll move to the next question.

Our next question is from Jason Gammel from Jefferies. Please go ahead.

Thanks very much. I had two questions please. First, Simon, I wanted to come back to some of the comments you made around both the divestiture process and the Permian. The Permian does seem to be one of the few places globally where upstream assets are attracting some pretty solid valuations and you referenced obviously being in a very good neighborhood there. So what do you think about the idea of monetizing some of the acreage position while maintaining your core and putting a pretty solid set of runs on the board from a transaction there. Second question is on the LNG business. The sales volumes are now up about 50% from prior to the BG merger. I was just wondering, Maarten, if you could talk about how the scale and flexibility have changed and how that affects how you run that business? I'm thinking, in particular, in terms of accessing new customers and of even potentially terming out some of your hub-linked and spot contracts into longer term?

Jason, thanks. Obviously, I'll leave the second one for Maarten. You're absolutely right, Jason. The hottest properties on earth at the moment seem to be in the Permian where $50,000 an acre appears to be the going rate. We actually have two smaller packages on the market at the moment that are good acreage. They're not that contiguous or close to our likely development activities, so let's see how that process unfolds. More generally, in terms of the shale businesses, we're thinking why do we want to own a shale? Well, partly, because we can. We have great acreage 12 billion barrels of total resource we've talked about previously, five basins Argentina, two in Canada and two in the U.S. And as a strategic element of the portfolio, it offers an optionality and a flexibility that we don't get in the rest of the portfolio, i.e., we can ramp investment and development up and down according to price and opportunity. If we don't have that in the portfolio, then we don't have that optionality, and we have less resource to work with as well. So, that's the reason we want the shale business. The Permian is to an extent currently and possibly, for quite some time, it is the crown jewel, not just in terms of the value and quality of the asset but also the capability that is being developed there. We and the industry learn more when there is more activity ongoing about how to maximize the value. So, it is important for us to be in the Permian, but that doesn't mean we need every acre that we currently hold, nor that we're not interested in adding acreage. And the patchwork nature or the patchwork "nature" of the acreage across the basins in which we're interested, may offer opportunities over time there as well. But the aim is focus so that we end up with a more efficient development program. And the areas or acreage that we're not likely to invest in, in the near term that we sell them rather than leave them sleeping. So, that is the aim. So we're actually, at the moment, following your advice. They were small enough packages not to be on the list of 2016 because there was a materiality criteria. It'd be interesting to see it by the time they get priced, they creep on to the list of 2016. Maarten, sales volumes and LNG in general, what the thinking is.

Yeah, thanks for the question. We could spend a bit of time on this if we wanted to. But I'll try to keep it short. Indeed, our LNG volumes, our sales are now about 15 million tonnes a quarter, so that brings us up to well over 50 million and actually close to 60 million tonnes a year, which is almost 25% of the current LNG market. So, that clearly gives us enormous footprint in terms of supply options. And does a few things for us. One is that in the LNG market, the business model of finding a big Asian utility to take 4 million tonnes a day at a high oil-linked price of your hands at high seas, is still going to be relevant going forward, but it's not where the growth is. The growth is in smaller customers that look for smaller volumes, also have worse credit. And also often only have one or two contracts in their portfolio and they need security of supply, they need certainty of delivery. And, in many case, what we're actually finding is that it's easier for us to win the business with those customers. Because we have so many supply options to give them security, but also because we are one of the very, very few suppliers and the State of Qatar would probably be the other one that doesn't need a condition precedent on a future FID when we make a supply promise. Because we have enough size and flexibility in the portfolio to promise someone 1 or 2 million tonnes without having to take an FID to back that up. And that isn't only the case with customers, that is also very much the case with countries who are starting to import LNG for the first time. Jordan…

Thanks, Maarten. Next Question?

Our next question comes from Biraj Borkhataria from Royal Bank of Canada. Please go ahead.

Hi. Thanks for taking my question. I had one for Simon, one for Maarten. For Simon, just following up on your comments on gearing, you're currently at 29%, but you did say that 2% of that doesn't really count. So I was wondering if I should think of your – should I think of your gearing ceiling as 32% rather than the 30% you've previously talked about? And I know that's a fairly small margin, but given you're quite close to that, I thought it's worth asking. And then for Maarten, just an easy question, could you provide any kind of update on Lake Charles and how that's progressing? Thanks.

Thanks, Biraj. You're absolutely right that like-for-like, when we started talking about 30%, that the 2% is different because it's on balance sheet finance leases. The rating agencies look through that anyway. Their debt figure is considerably higher than the 77% that you see on the balance sheet today. So 30% is just a proxy for their overall metrics. It's not an immediate trigger either to them or us if we go through 30%. It's just a signal that we need to be giving extreme priority to bringing it down again because if we stay above 30% whether it's 30% or 32%, that becomes a less sustainable financial framework over time. So, we stick with 30% as the proxy. That's what we like to manage to. It's easy to remember. But like-for-like, indeed, really it's 2% higher in terms of the economic substance. Maarten, Lake Charles?

Yeah. Thanks, Simon and, Biraj. Lake Charles is – and I think Lucas earlier on the call mentioned the Permian as one of the sleeping beauties in the shale portfolio. I think Lake Charles is probably in its own way a sleeping beauty from the ex-BG portfolio that we are – that I am very, very pleased to have in the portfolio. It is an extremely competitive U.S. LNG project, obviously brownfield. But the way BG has built this up, has designed it, and has pulled it together is first class. And so, it's a very good opportunity to build LNG supply right at the left-hand side of the low end side of the cost curve that we would benefit from. So, the trick here really is to try and judge when is the LNG market going to need this volume again. As you will have seen, if you check this market, in the last 18 months, we've really only had one FID that was the new train on Tangguh by BP and most of that LNG is actually going to stay in Indonesia. But apart from that, it's been dry in the industry and it could remain dry for a bit. And that's not a bad thing because there's a lot of energy coming into the market as has been noted before on the call. But somewhere in the course of the early 2020s and whether that's 2022 or 2023, is going to depend more on demand than on supply and there are some good signs on demand. And this market is going to rebalance and inevitably then go short, because the supply reaction is always delayed, of course. So the trick is really when do you take your best supply projects into an FID to be there when the market needs the volume and is willing to pay good prices for the volume. That is not today. It's my feeling that would and has been our decision. And so we don't really think this is the right time to take an FID at the moment. And also we look, of course, at the affordability in the company and we say that's actually quite convenient that we are able to postpone this piece of capital. But it is certainly a project that I'm very pleased having a portfolio, an option that is a good one for us to have. And hopefully find the right time to exercise it and bring it into the onstream portfolio. But that's – and we review that periodically,

Thanks, Maarten. Okay. Next question.

Our next question comes from Alastair Syme from Citi. Please go ahead.

Thanks very much. Hi, Simon and Maarten. Can you just talk about your long-term strategic planning? I think you've traditionally done this in the third quarter. And I just wanted to confirm that you've done this exercise, again, this year and did you change your internalized long term view around oil and gas markets? And secondly, this is a very quick question. Can you remind us of the state of play on the Showa Shell and Motiva disposals? Thank you.

Thanks, Alastair. The first one could be a long or short, so I'll keep it short for this call. The – what we do – in essence is through more a three-year strategic planning cycle where we do a full bottom up around the portfolio once every three years and reaffirm strategic intent. We really did that last year as we were still doing the BG deal. So this year, we updated it in an assessment. But that in itself has turned up some questions around gas markets, gas pricing, and actually Maarten's pretty much given you the oversight of how we think about those already. Oil, we've long been of the opinion that demand will peak before supply. And that peak may be somewhere between 5 and 15 years hence, and it will driven by efficiency and substitution, more than offsetting the new demand for transport. We still have that view. We still have a view that there will still be a substantive business for us for many decades to come as a result. And that also the reason Maarten also had the new energies business and his mandate is that actually new forms of energy used for transport such as gas or electricity, or biofuels, or hydrogen will actually form part of the future energy system after the transition. And therefore, even if oil demand declines, its replacements will be in products that we are very well placed to supply one way or the other, so we need to be the energy major of the 2050s. And that underpins our strategic thinking. It's part of the switch to gas, it's part of what we do in biofuels, both now and in the future, second gen, third gen. And hopefully it will be part of how we develop the…

Ladies and gentlemen, this concludes the question-and-answer session. I would now like to hand the call back to Mr. Simon Henry, CFO.

Thank you very much. Well, thanks everybody for calling in. I realize it's been a busy day where with two sets of results and more. Thanks for the questions. Pretty good coverage today and some really important issues covered. Hopefully, both in the presentation and the answers you can see evidence that the portfolio, both the Shell portfolio and the way it now combines with BG has quite some power, power to perform as we're going forward, power to generate cash and power to deliver the value that we state as when we first did the BG deal. And I keep on needing to repeat AUD 64 billion acquisition. We are 19 months since announcement, job done, synergies being delivered, value being identified. We know who's delivering it. How it's going to be delivered. Two companies together, same cost base as one company. We've done this years ahead of expectation. Not our expectation, but the expectation external to the company and that is really having an impact today now on the underlying financials that you see. Now, we will be having an Investor Day in New York next week on November 8, actually one week today. Ben, myself, and several other members of the executive team will be in attendance and we really look forward to talking with you face to face then, and giving you the chance to hear a bit more and ask a few more questions about the substance behind the comments made today and the performance that you see. So thank you for your time today and look forward to seeing you. Take care.

Ladies and gentlemen, this concludes the Royal Dutch Shell's 2016 Q3 results announcement. Thank you all for your participation today. You may now disconnect.