Shell plc (SHEL) Q3 2015 Earnings Report, Transcript and Summary

Welcome to the Royal Dutch Shell Q3 Results Announcement Call. There will be a presentation followed by a Q&A session. I would like to introduce you to your host, Mr. Ben van Beurden. Ben van Beurden - Chief Executive Officer & Executive Director: Okay, thank you, operator. Ladies and gentlemen, welcome to today's presentation. So we've announced our third quarter results this morning and you would have seen some substantial headline losses on your screen this morning. There are significant one-time charges in these figures which are a consequence of actions that the Shell management team are taking on portfolio as well as, of course, the impact of lower oil prices. So what I wanted to do is to update you on that, and then Simon will take you through the numbers and, of course, there's plenty of time for questions afterwards. Before we start, of course, the disclaimer statement. So Shell current cost of supply earnings for the quarter were a loss of $6 billion and these results included $7.9 billion of identified items and around half of these charges, $3.7 billion to be precise, are primarily related to a revised oil and gas price outlook and the remainder, $4.2 billion, is a result of management actions on the longer-term portfolio. Now if you would exclude these impacts on an underlying CCS basis earnings were $1.8 billion with $11 billion of cash flow and a $0.47 per share dividend declared. And these results were underpinned by a strong downstream earnings and a strong performance on uptime, volumes across the company. The recommended combination with BG is on track and we are expecting completion of this transaction, subject of course to Shell and BG shareholder approvals and also the satisfaction of the pre-conditions, in early 2016, pretty much as planned. Now let me update you on the portfolio actions that we have taken and, of course, some of this is flowing into the charges that we have taken in the quarter alongside that reduction in oil and gas price assumptions that I mentioned. But first let me recap on the exploration in Alaska, where we had some drilling results in the quarter. We've completed the 2015 drilling season. We drilled the Burger J well through its target depth. This well was completed safely, was on schedule, in what is probably the most regulated and high-profile exploration province in the world. But it was a dry hole and we are currently in the process of safely demobilizing from Alaska. And while Burger turned out to be uneconomic, there are of course other potential prospects in our Chuckchi leasehold as well as other areas offshore of Alaska. However, due to the high cost and the challenging and unpredictable regulatory environment we have decided to cease further exploration activity offshore of Alaska for the foreseeable future. The leases that we have in Alaska expire between 2017 and 2020 and the U.S. government recently denied Shell's request for lease suspension, which would have extended the expiration dates. And we are of the view that the U.S. government should simplify and modernize the permit process, if there is any ambition to develop oil and gas in the offshore of Alaska. So how does this decision fit into our strategy overall? We're moving forward with the preparation for the recommended combination with BG, and we are aiming to complete this deal in early 2016, as planned. The transaction is important opportunity to create a simpler and a more profitable Shell, so what we call "grow to simplify," and major elements of that refocused strategy are under way today as we review and reduce Shell's long-term option set. Of course we have Alaska, just mentioned that, and in heavy oil we have decided to hold the development of the Carmon Creek project in Canada, an in-situ oil project. After careful review of the potential design options, updated costs, the company's capital priorities, etc., we have taken the decision that the project simply does not generate suitable returns. Elsewhere in these longer-term themes, portfolio restructuring is essentially complete. In our shale businesses, we have retained attractive options in the Americas and we have reduced pretty much elsewhere. In Nigeria we have reduced exposure with a $4.8 billion asset sales program in SPDC in the last five years and we're also reviewing options in Iraq. So overall, we are making changes to Shell's mix by reducing our longer-term upstream options worldwide and managing affordability in the current world of lower oil prices. And this is driving tough choices at Shell and I hope this sets the context for the charges in the results that you have seen today. Now let's turn to the quarter. Let me hand you over for that to Simon first. Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Ben. Good afternoon, good morning. I'll start with the macro. Shell's liquids and natural gas realizations declined substantially this quarter compared to the third quarter 2014. Brent crude oil prices were some 50% lower than a year ago, with similar declines in WTI and the other markets. We realized gas prices were 18% lower than year-ago levels with strong decline in gas prices seen in North America. On the downstream, the refining margins around the world continued to be supported by the lower crude prices and also by robust demand and industry refining downtime. The industry base chemicals margins declined in North America as ethylene prices fell with the crude. Intermediates' margins increased on the back of reduced feedstock and the energy costs and improved market conditions. Now turning to the results, excluding identified items, Shell's current cost of supply, or CCS, earnings were $1.8 billion. That's a 70% decrease in earnings per share from the third quarter of 2014. Within that $1.8 billion figure, there was $1 billion of non-cash charge related to currency movement which were not taken as an identified item. On a Q3-to-Q3 basis, we saw significantly lower earnings in the upstream and higher earnings in the downstream. The return on average capital employed, excluding the identified items, was 5.5 percentage points. Cash flow generated from operations was some $11 billion. Our dividend distributed through the third quarter of 2015 is the same as a year ago of $3 billion, or $0.47 per share. Turning to the business segments in a little more detail, first the upstream. The earnings excluding identified items for the third quarter were a loss of $425 million. The oil prices have halved from the year ago and that, combined with the gas price movements, together reduced the upstream results by $4.4 billion. The results this quarter did include a negative of $761 million of non-cash tax effects related to movements in the Brazilian reais and the Australian dollar. They also included a higher level of well write-offs. Integrated gas results within the upstream figures were $824 million in the quarter and that compares to $2.8 billion a year ago. Again, the majority of that decline was oil and gas price-related, around $1.4 billion. But in addition, last year the Q3 results in integrated gas included a catch-up dividend payment from an LNG joint venture of around $200 million which has not recurred this year. And also, this year the integrated gas results do include a $470 million non-cash tax impact for the movement in the Aussie dollar, and that's a negative movement of course. The results in the third quarter this year also exclude dividends from the Malaysia LNG Dua joint venture. They were a year ago $195 million. That's a joint venture that we've now exited, so no contribution this year. So you see, there's quite a few moving parts in these upstream results. But I think it's important to note that our actual underlying upstream operating performance continues to improve. The focus on reliability and uptime and the project growth is delivering, with an increase in production, decline in operating costs and successful exploration appraisal wells at KKS and Power Nap, both in the Gulf of Mexico. Now the headline oil and gas production for the third quarter was 2.9 million barrels of oil equivalent per day. That's 3% higher than last year. However, the underlying volumes like-for-like, they increased by nine percentage points. This was driven by improvements in the operating performance and we saw lower levels of unplanned maintenance compared with the same quarter last year. The underlying volumes also strongly supported by the ongoing ramp-up in deepwater fields in Nigeria and Malaysia and in the Gulf of Mexico, and that alone more than offset the impact of the field declines. Our LNG sales volumes in the quarter were some 5.3 million tons. That's down 6.5% Q3-over-Q3. That mainly reflects lower volumes as a result of the expiry of that Malaysian Dua joint venture. Turning now to the downstream, the earnings for the quarter excluding identified items were $2.6 billion. That's driven by higher results in both oil products and chemicals. Oil products, we benefited from increased refining margins and lower costs, some offset from lower contributions from marketing; however, that was mainly as the result of exchange rate movements and divestments. Chemicals earnings were 15% higher than a year ago, in turn driven by improved market conditions and lower energy costs for intermediates, partly offset by the weaker base chemicals environment due to the falling ethylene prices and the outage at the Moerdijk plant in Europe. Overall, this was a strong quarter for the industry. And so our return on capital on a clean CCS basis was 19.3% at the quarter-end, with the downstream cash from operations generated around $16.5 billion over the last four quarters. The cash flow for the group as a whole on a 12-month rolling basis was some $34 billion at an average Brent price of $60 a barrel. Free cash flow, that's after deducting the investments, was $5.5 billion in the quarter and $11 billion over the last 12 months. Gearing on the balance sheet, the debt divided by debt plus equity, was 12.7%, and that's essentially unchanged over the year despite that significant downturn in the oil price. Our returns to shareholders, that's the dividends declared plus the buybacks, was $13 billion over the last 12 months. Now some of you have asked us about dividend affordability against the backdrop of low oil prices today. So let me just share with you how we think about this. We plan the financial framework on a long-term multiyear basis, not for any given year or quarter. We aim to balance the cash in and cash out across the cycle wherever the prices might be. You can see on the chart here that Shell has delivered on this strategy both on a long-term, up to five years, and the short-term, over the last 12-month basis. Our oil price cash breakeven point over the last 12 months has been around $60 a barrel, or the same as the actual price. And we have options to further reduce that going forward such as asset sales and capital investment levels. As an example, as we go forward, $5 billion of divestment proceeds in a given year approximately equate to a $10 movement in the oil price breakeven for any given year on a cash flow basis. The combination with BG enhances Shell's free cash flow, improves our dividend potential in any expected oil price environment. And in the future, one of the key elements of the BG deal is moderated capital spending, a higher rate of asset sales, and more of the shareholders' cash returned as share buybacks. So let me sum up. Our integrated business and our performance drive are helping to mitigate the impact of lower oil prices on the bottom line in what is admittedly a difficult environment for the industry today. While our underlying performance in the quarter was strong, the headline numbers we report today including the charges reflecting both the lower oil and gas price outlook, but also the firm steps that we've taken to review and reduce Shell's longer-term option set. The BG deal itself, that remains on track for completion in early 2016, and it will be a springboard to focus the company into fewer and more profitable themes, especially of course deepwater and the integrated gas. With that, I'd like to move to take your questions. But also just let me remind you that we're having a Management Day in London next week on Tuesday followed by a day in New York on Wednesday, so prefer if possible to keep the Q&A today to the quarter and we can expand more next week. And please, could we also just keep ourselves to one or two questions each so that we give everybody a chance to get in a question. Thanks a lot in advance. Operator, please, could you poll for questions now?

Thank you. We will now begin the Q&A session. Our first question today comes from Theepan Jothilingam from Nomura International.

Yeah, hi, good afternoon, gentlemen. Just two questions. Firstly, you discussed sort of a cost improvement target of around $4 billion earlier this year. I was just wondering how much of that has filtered through into the Q3 numbers and if you could break that down between upstream and downstream. Secondly, and I imagine you'll talk a little bit more about this next week, but just upstream Americas remains a problem child and that's been exacerbated by lower liquid prices. Was there anything in particular outside simply the operational gearing that we saw come through in Q3 that might reverse out if we look into 2016? Thank you. Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Theepan, good afternoon. The $4 billion cost reduction wasn't really a target. It was an achievement. We had already done it. So, yes, it's already there and we also said we expect to see further improvements. It's roughly split between upstream and downstream. We're currently putting together our expectations for 2015, but certainly on a like-for-like basis we would expect to see further improvements, so all of it in year-to-date effectively. On the upstream Americas, remember there's a combination of businesses in there: deepwater, Alaska, the heavy oil and the unconventional, the shale business. There is a one-off charge of around $300 million on the Brazilian deferred tax that is included in upstream Americas. And other than that, there's not too much one-off that really relates in the clean earnings. Of course, quite a lot of the impairment one-offs were indeed in the Americas. So the issue is really realized oil and gas prices. And while the costs are certainly coming down there, we will need to take more out in the current price environment to return to profitability. The actual performance of the assets, both in the heavy oil and in the Gulf, was better than a year ago, underlying performance, reliability up. And in the shale business, for quite a reduction in the capital investment, we are maintaining the production levels and target that were originally posited before we reduced the investment level. So, in general, good progress but not enough to see a big impact yet on the bottom line. Ben van Beurden - Chief Executive Officer & Executive Director: Okay. Thanks for that. Operator, can I have the next question, please?

We will now take a question from Oswald Clint from Sanford Bernstein. Please go ahead.

Thank you, yes. Thank you very much. Maybe two questions on North America. Sorry, the first question, I wanted to ask about the impairments in the upstream. I think it's North American gas potentially, Duvernay or Groundbirch. Could you talk about the gas price changes that have been incorporated into that exercise? And also does it imply anything about your appetite for kind of West Coast Canadian LNG exports? That's the first question. And then secondly, maybe just on Carmon Creek. I heard your comments. I just want to know in addition was there anything with respect to the technology or actually the reservoir in terms of the Carmon Creek that forced you to make this decision? Thank you. Ben van Beurden - Chief Executive Officer & Executive Director: Okay, thanks very much, Oswald. Good questions. Let me take the first one – well, actually I'll be happy to take them both. Let me talk a little bit more broadly on our oil and gas price outlook changes. You know, the screening values that we have been talking about before I think ultimately ended up being characterized almost as a central management tool, which of course they're not. They also at some point in time got characterized as a Shell forecast, which of course they also are not. So the reality is that we manage the company differently. We manage the company on the fundamentals of the market and on the reality of the day, and if you look at the fundamentals, be it oil or gas, the point is that industry will not invest trillions of dollars if the price, if the cost is such that you can't make a profit. And if the investment slows down, supply will quickly fall short of demand and as a result of it prices go up, costs will come down, or a combination of the two. The reality is of course that we don't know when this process plays out, how it plays out, at what level it stabilizes and whether or not there will be sort of remaining volatility as a result of all of this. So the way we are looking at projects now is not so much that here is the screening value, but it's really how can we make sure that all our projects that we are considering are resilient, are completely competitive in their class to a point that we are clearly ahead of the rest. Because the industry needs to exist, it needs to make a profit and we want to be ahead of the curve, so to speak. Now the other part of the reality of the day is that we have to live within our means, and that means living within our means at today's oil and gas prices and that essentially is, as you heard from Simon, what we are doing. We live within our means at $60, which the oil price on average has been over the last 12 months. That's how we manage the business. That's also how we want to talk about managing the business going forward. So yes, indeed, if you look at where oil and gas prices might go in the future, they will probably have a more conservative outlook than what we had before. But I do not want to characterize numbers here and then see them being used as management tools, which as I said they clearly are not. Now what does it mean for LNG Canada? We are in the middle of the defeat for LNG Canada. Of course if you look at gas prices in North America, you can imagine a downward adjustment is actually going to improve the economics of a project that fundamentally takes a margin between U.S. gas prices and North Asian gas prices, but at the same time that's not the only driver. Again, I go back to my principles. This project needs to be ahead of the pack. It needs to deliver the most competitive LNG into the target market and we need to understand how resilient that is due to the volatility that we will no doubt continue to see in oil and gas markets in both sides of the Pacific. That decision will come up later in the year. I think I'll leave it that. We'll take that discussion again when we are near an investment decision point. On Carmon Creek, yeah, there were a lot of moving parts in Carmon Creek. So many things have sort of continued to evolve since FID – costs escalation; evacuation routes that worked out differently and became rather uncertain; of course, the whole oil price environment, not just the global oil price environment, but the Canadian oil price dynamics. And the upshot of it is, again, the project turned into a project that was just not sufficiently resilient in today's environment. So we closed it already earlier in the year. We had been working on cost and getting more certainty around evacuation options. We got the costs back in control again more or less fully, but ultimately we were looking at a project that was just not resilient enough to go ahead under the affordability pressure that we have. And the only sensible going forward was to basically shelve it. Incredibly tough decision to do but also simply necessary. There was nothing in the technology as such that made that, if you look at sort of fundamental technology of steam injection in these types of reservoirs, it was just the economic resilience and the affordability that just didn't make us comfortable to go ahead. Thanks for these questions, Oswald. Can I get the next one?

Brandon Wong (sic) [Brendan Warn] from BMO Capital Markets has our next question.

Yeah, thanks, gentlemen. It's Brendan Warn from BMO Capital Markets. Just two questions if I may. Just first question, this I guess relates to the acquisition of BG. And just in terms of current oil price and if we took the forward curve as given as an example, can you just talk around the share buyback and the pressure that may be under the share buyback in terms of what trigger points you'd look at to buy back shares that you previously announced from 2017? And then I guess just a second question, again just relating back to Carmon Creek. If you could just talk around if this is a one-off in terms of post-sanction cancellations. I appreciate it's a tough decision, but if we're still in this environment certainly in the next couple of quarters from here, just sort of what percentage of committed CapEx spend is at the edge of assessment in terms of cancellation, please? Ben van Beurden - Chief Executive Officer & Executive Director: Yeah, thanks, Brendan. Let me take the Carmon Creek one, and then Simon will talk about share buybacks. Yeah, I think Carmon Creek was quite a special case, challenging project because of the economic environment in which it had to operate. As I said, not just cash costs but also the very, very difficult dynamic that we had in oil prices, and not just the bitumen price that you would see in Alberta, the bitumen netback, but also the whole pricing dynamic around bill events, the uncertainty around the evacuation route. And ultimately it was just too many things coming together conspiring against the project that made the project not just attractive enough but also not resilient enough to have the comfort to take it forward. And we had of course several billion dollars of investment still outstanding. So I think it is a relatively unique case. The other thing you have to bear in mind, of course, it's an onshore project, it's somewhat easier to hold. You may argue that if what comes close to something that is always on the cusp of, will we go ahead or will we hold back, is shales. But that of course is a less punishing type of decision because you can take it a little bit more, the investment decision, you can take a little bit more a hand-to-mouth approach. So you will see us flexing that a little bit more simply because we can without too much penalty. But no, I would characterize this to be an unusually tough decision to take and I would not expect that to be candidates in the current portfolio project that we are bringing on stream. Simon? Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Ben. I will also note, on Carmon Creek, it's 100% Shell, so something we have more control over to make a decision. On the BG deal, I'll sort of expand a little on the question, if I may. We're getting a lot of questions around pricing and the value of the deal, so just to be clear, the deal was deliberately structured back in April with 70% equity, 30% cash. The equity ratio share-for-share is fixed, so as oil price and therefore share prices have varied, the deal offer varies as well. So on the day of the announcement, it was $70 billion for the common equity. Four weeks ago, that amount readjusted to $56 billion, therefore a 20% reduction. As of this week it's in the low $60 billion, so more than a 10% reduction. These share prices, both companies and the sector, tend to reflect the forward curve, so there is in essence a natural hedge in the market as we go through the period, and that's precisely how the deal was structured; it's working. Now that doesn't necessarily help with the – and will the cash be available in the future to execute buybacks if the oil price stays at $50. The forward curve of course doesn't actually extend out in any meaningful way as far as the buyback period, 2018 through 2020. It only actually reflects storage costs, either putting it in or taking it out. It has nothing to do at all with the fundamental supply-and-demand characteristics of the market. Having said that, if the oil price stays at a low level because the marginal costs get set at such a low level, then the buyback program is going to be more challenging to execute, but the determination to do so over a period is completely unchanged. It is an essential part of the offering to shareholders post the completion of the BG deal. First we address the debt characteristics, the rating, and secondly we return cash to shareholders. And that's a fundamental principle that will apply whatever the price happens to be as we go forward. Ben van Beurden - Chief Executive Officer & Executive Director: Okay. Thanks for that, Simon. Thanks for the question, Sir Brendan. Operator, can I have the next one, please?

Lydia Rainforth from Barclays has our next question.

Hi. Good afternoon. Two questions to focus on the numbers, if I could. The first, just thinking about the cash flow from operations for the quarter, clearly those numbers, the $11.3 billion (31:01), you then got $5.3 billion given the same as increasing working cap. But what I'm thinking about what is an underlying and ongoing cash flow number, if I add up the inventory holding offers it gets me to about $6.6 billion. Is that the right way to think about the cash generation over this quarter itself? And then secondly, just a very quick one, the writedowns in OCR, did that relate to the Arrow project? Thanks. Ben van Beurden - Chief Executive Officer & Executive Director: Simon? Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Lydia. Working capital movement is always a bit volatile and not always representative of inventory, which actually went up in the quarter in volume terms; was obviously down in price. It was a high movement. There are movements in there that are driven by the provisions, for example, that we took relating to Carmon Creek and Alaska. So to be representative the other way around, take the clean earnings and add back the non-cash $1billion or so on currency, and around $4.3 billion of depreciation per quarter. We start with an EBITDA-type number, but then take off effectively the tax payments are not aligned either with the tax charge. You get to a more representative figure, which is not that far off the figure you've got but a little bit higher. So between $7 billion and $8 billion is probably the underlying cash generation from ops. Writedown in OCR, we looked at I think clearly lower oil and gas for longer. There are implications from lower gas prices, Henry Hub in North America, explicitly noted in OCR we have multiple assets, most of which, although they're gas production, are ultimately exposed to oil prices because of the netback from Asian LNG, so wouldn't identify any one asset but there are multiple assets down there. Thanks, Lydia. Ben van Beurden - Chief Executive Officer & Executive Director: Thanks, Lydia. Thanks, Simon. Can I have the next question, please, operator?

Irene Himona from Societe Generale has our next question. Irene Himona - Société Générale SA (Broker): Thank you, good afternoon. Ben van Beurden - Chief Executive Officer & Executive Director: Hi, Irene. Irene Himona - Société Générale SA (Broker): I had two questions. Firstly, on the FX, the $1 billion non-cash input on the P&L. Obviously we have zero visibility on that and normally companies would take such a move through the balance sheet. Can you just remind us of the logic of taking it through the P&L, please? And then secondly, very quickly on CapEx, you have spent $20 billion in the nine months, just under $7 billion a quarter, your guidance remains for $30 billion. Are you likely to undershoot, do you think, this year or are we going to see quite a step-up in Q4 spending? Thank you. Ben van Beurden - Chief Executive Officer & Executive Director: Thanks, Irene. Simon, will you take them? Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Irene. Indeed, there are three elements to the FX move this quarter that we have deferred tax assets in Brazil and Australia, which are slightly complicated in terms of the way that the currency moves on it, but we have given sensitivities through the IR team on what they may be. And they basically reflect the exchange rates on the last day of the quarter. There's no choice as to whether they go through the P&L or not. They are not balance sheet items in terms of the way they translate. This quarter there are a few other currencies where we have loans, some of them intergroup, held in non-U.S. dollar currency because that's the currency of operation in those activities where the general strengthening of the dollar has also added some negatives. So it's effectively $761 million in the upstream and couple of hundred million in corporate in the quarter. The other question we are regularly asked is why don't we identify them separately, and some companies definitely do this and some don't. The primary reason is that we don't change our policies on what we report on a serendipitous basis. It's a fair question, now it becomes so material and so volatile with limited means at our disposal to actually reduce that volatility. So it may be something we think about going forward. But we typically don't make changes in the middle of the year. The $7 billion a quarter capital investment, there is some uptick in Q4 partly – it's mainly in the downstream, partly will be driven by turnaround and partly by the back end of the year retail activity. There is more marketing spend that tends to be later in the calendar year for a variety of reasons. I can't really give a more accurate figure than that. But we said $30 billion or we would be doing better. The trend is exactly as you state. We have quite a lot of – tens of thousands of people working on this, not just Ben and I. So the good news is that the right decision is being taken in many different parts of the organization. We have not given an indication for 2016 other than to say on completing the combination with BG we'd expect the combined capital to be around $35 billion. No reason to change that statement today. Ben van Beurden - Chief Executive Officer & Executive Director: Yeah. Okay. Good. Thanks, Simon. Can I have the next question, please, operator?

Our next question comes from Fred Lucas from JP Morgan.

Thank you. Good afternoon, gentlemen. Two questions, if I may. The first one on impairments. Could you specify what price curve you've assumed for the Q3 impairments and also perhaps the sensitivity were you to reduce that curve by $10 a barrel? And related to impairments, the $60 billion or thereabouts that your deal for BG is currently valued at, that implies quite a sizeable balance sheet uplift to the value of BG's assets, order of magnitude $25 billion, $30 billion. So I just wondered how safe that uplift would be to your current impairment test. The second question is on exploration. Obviously, you have good and bad quarters, Q3 perhaps not a vintage one with Burger J and E&I's discovery on Shell acreage in Egypt. I just wonder where you think the internal decision-making at Shell regarding what equity exposure you should take in blocks and when or when not to relinquish blocks is really fit for purpose. Ben van Beurden - Chief Executive Officer & Executive Director: Okay. Thanks, Fred. Let me take the second question first and then Simon will talk a bit about the impairments. Yeah, I think it's a fair question and a question that we have to address. If you look at Alaska, the only good news about Alaska is that it was a very conclusive result, so at least we knew immediately what to do as a result of it. But of course it's a very expensive dry hole and of course we can rationalize that to a large extent by sort of pointing at the unbelievably complex regulatory environment that we were looking at. Of course, generally you would expect exploring in this type of climate to be more expensive because of the weather and the remoteness and everything else, and you would of course only do that if there was a significant amount of barrels to be potentially discovered. But as it turned out, this one went bad on us. I am not going to just say, well, you know, that's exploration, even though it is what it is. We will have to look back and say let's take a good view on how we got here and, without sort of rehashing the 2012 season, let's just try and learn from this as much as possible. Also on what sort of review points did we take and, with the benefit of hindsight, should we have taken a different view and what can we learn from it. I think that's an important moment, an important thing to do in cases like this. Much, by the way, as we also have to learn from everything that did go well, because it has been an exceptionally difficult campaign and we have operated I think exceptionally well, and it would be remiss of me not to also on a call like this remind all of you how strong a performance the team has delivered, with lots of new capabilities, by the way, that has resulted from it that I'm sure we will use in other areas of the world where we have to deal with ice or very difficult conditions. But let's do that work. We will bring that back to the board as well as you can imagine. First priority now is to make sure that we safely demobilize from Alaska. Simon? Simon P. Henry - Chief Financial Officer & Executive Director: Impairments, we use a range of prices for all purposes in Shell, whether it's impairment, long-term decision-making, short-term trading, or otherwise. We don't use a single price deck. We did come down on the long-term assumptions for impairments. We actually do the first screening at the lower end of the range and then look at a more representative expectation to do the actual calculation for impairment. So I can safely say that if we brought the price down, there wouldn't be any more assets at risk. One might argue that the actual impairments taken might be slightly higher but not materially higher. I don't think in the sense going forward whether we would do anything differently. And just to note, the biggest impact was the reduction in the Henry Hub price, not the oil price and the impact that had on gas assets in North America. BG, it's a good question. This is a little complex. I'll take just a moment to explain to those and maybe others up to speed as Fred. The assets for BG, when we bring them on to our balance sheet at the date of completion, will be recorded first at fair market value; that's a third-party valuation, so it will be partly based on what you guys think. It will be above the current carrying book value of the BG assets for sure, and there will then be an ongoing amortization of that purchase price premium. The amortization we said back in April could be up to $2 billion a year, and that obviously plays in the earnings per share. As of today, almost by definition, you would give a lower fair market value, so make your own choice on what that might actually do going forward. Any remaining difference between that fair market value is then recorded as goodwill, and when I say difference that means difference between fair market value and the equivalent of the offer based on the share price on the day the deal completes. So again, it could be just about anything going from here to there, given the extreme volatility we see in the markets. We do not know what the goodwill will be. We have a reasonable idea where the fair market value will come out. As of today, we don't see any reason to be concerned on a future impairment. Of course, if the share price were to be excessively high with a large goodwill, that then gets tested for impairment every year thereafter to ensure that we still see the value from the totality of the BG assets within the combination. Thanks for the question, Fred. Ben van Beurden - Chief Executive Officer & Executive Director: Yeah. Thanks, Simon. Thanks, Fred. Can I have the next question, operator?

Our next question comes from Jon Rigby from UBS.

Hello. Hi. Just one question. It's about impairments really and sort of a broader perspective. It seems sort of the modern era of Shell is being periodically scarred by these events where you take very large impairment charges. And I think in the context of the company that is obviously deploying a lot of capital, a lot of CapEx annually, is there a problem there in terms of the process by which you go through thinking about how you deploy capital and could that be tightened up, the process be tightened up, going forward? Because it would seem to me that even though you've talked about a fairly sophisticated process and you've talked about the environment and the scenarios, there is evidence that you periodically get it quite wrong. Ben van Beurden - Chief Executive Officer & Executive Director: Yeah. That's a good philosophical question, Jon, and it – of course, charges and if I characterize, for instance, what happened in the last kind of charges that come with it, you will have them as a result of the nature of our industry. But I'm sure that's not exactly what you are referring to. It's more impairments on assets, leaseholds, operating assets that we have on the balance sheet. The only thing I can say is this has been of course a significant focus area over the last few years. I'm not going to sit here and say, no, impairments are actually good and healthy and we use it as a way to clean the cupboard out. That would be the complete wrong way to characterize it. I think we have to make sure that in the main you import impairments that can clearly be traced back to poor decision-making around capital investments and deals that we have done. And a lot of the focus, one of my key priorities from day one, has been how can we improve decision-making around capital investments and deals and how can we do that by making not only the decision process more robust but also make it much earlier in the cycle. And ultimately I think it is processes like this where we have better visibility, earlier visibility, much clearer guidance on what you want to see in terms of Brazilians and tying it into very well-articulated strategic intents for each of the investment themes. These are going to be the processes that need to get it right. It is tough that you have to make decisions that lead to impairments. Believe me, I don't like them at all. But you have to take them in the environment that we find ourselves with the legacy that we have in certain areas. But the processes that we have in place are clearly designed to make the decision process and the resulting portfolio from it much higher quality, much more predictable. Okay. Can I have the next question, please, operator?

Martijn Rats from Morgan Stanley has our next question. Martijn P. Rats - Morgan Stanley & Co. International Plc: Hi. Hello. I just had a quick question about slide number six in the short bank that you published. At the bottom there's a comment on Kazakhstan. The title of that page is "actions taken" and it refers to Kashagan and BG asset potential. I'm just wondering what actions are taken in that area. I wasn't quite sure what that bullet point referred to. Ben van Beurden - Chief Executive Officer & Executive Director: I think it's just an indication what – well, first of all, we always said the longer-term themes, we have also what we call INK internally – Iraq, Nigeria, Kazakhstan – and we have to take a view on how these are going to be long-term positions for us because they have unusual characteristics. And different countries in that category have different types of characteristics that make them unusual. I talked about Nigeria, which is basically sort of restructuring the portfolio. I mentioned Iraq, which is basically reviewing Majnoon and looking at what do we want to do with full field development, how do we take into account the directives that we get from the Iraqi government to spend less and what are the consequences of that. That particularly affects Majnoon, much less so the Basrah Gas Company. And then Kazakhstan, of course, has two things in it. Kashagan, which, of course, we need to see how that will come on stream exactly, hopefully late next year or early 2017. And of course what is the potential of the BG assets when they come in. So it was more mentioned for completeness sake. We don't have a particular review that is going on on Kazakhstan other than to say that these two, of course, are very material positions if you add them together. So Kazakhstan will become quite an important country, but also a country that has very, very long-live assets. So I would not read anything else in it and just mentioning it for completeness sake. Thanks, Martijn. Can I have the next question, please?

Our next question comes from Thomas Adolff from Credit Suisse. Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.: Hi, Ben, Simon. Two questions as well. Firstly, on the BG transaction, I wondered how the two integration teams are working and whether you have any interesting update now that you have access to a bit more data, if you will, positively surprised or negatively surprised? And secondly, just going back to this thing you call cultural change, I think generally people have the perception that Shell will struggle to change culturally. You are a very complex organization. So when you talk about this platform for cultural change, can you perhaps give some example that the entire organization is actually buying into your strategy and maybe some examples that are harder to see for an outsider like myself, and what this BG transaction will actually do to accelerate this thing you call cultural change? Thank you. Ben van Beurden - Chief Executive Officer & Executive Director: Thanks, Thomas. Simon, why don't you have a start and I will pick it up. Simon P. Henry - Chief Financial Officer & Executive Director: Many thanks. I'll just talk about the integration really. Thanks for the question. We have about 40 people working roughly half and half from Shell and BG together, separate office, separate team, 19 defined work streams and an environment in which it gives me great confidence that the two teams will be able to work together in the broader sense when we actually come together. Great contribution, positive, from all of the BG people involved. I think Helga has given a good steer that we're in this to create value and create a winning combination. And so far it's been a very positive experience. As we work, there are limits for the amount of data we can share, particularly as we're still competitors. So confidential information can't actually flow yet, but in general where it can I'll say there are ups and downs, probably more positives than negatives. I can't say anything more today in terms of quantitative, just that the mood music and the way in which the teams are saying, hey, when we come together, these are the things we could do, do go beyond just what you might think from looking at the paperwork. Ben van Beurden - Chief Executive Officer & Executive Director: Yeah, I think on the cultural change, let me say a few things, Thomas. But I'll also remind you that actually, when it comes to the BG combination, we will of course be going into this a bit more completely next week. So I may reserve a few things for that as well. There are of course areas where we believe BG is doing things very well and we want to make sure we learn from them. We know that they have a very, very good exploration capability in certain areas. We also know that they have a really first-class management of non-operated ventures, simply because that is the bulk of their portfolio. We tend to have still a slightly more sort of Shell-operated portfolio in the balance. We know that they manage their integrated gas business through their GEMS organization in a way that is slightly different from ours because they came at this portfolio model from a different way. We are both aggregators but they manage it in a slightly different way. And after that comes work processes, people capabilities, etcetera, that are just very worthwhile to understand how we pick the best from it. And so we have identified these and other areas as areas that we with the integration team called BG Magic, and we want to make sure that we sort of build them in to the combination going forward, and there's multiple different ways to do that. You can imagine it has to do with processes, structures and individuals, and that's exactly the three levers that we are using to make sure that this comes across very well. The other thing when you talk about complexity, Thomas, it's of course we are a large organization with many assets around the world and we have a model that is matrixed, which is pretty much what you have to do in a situation like this, and it's not going to change going forward. We will make sure that it works very, very well with the BG assets coming in, make sure that we have the same performance unit approach that we have in Shell also very much imprinted on the BG assets, which I think is actually going to be pretty straightforward. But then a lot of the other complexity that maybe comes from the breadth and the size of the portfolio, we are going to take out, not so much through a culture program if you like, but through a portfolio upgrade program, which is very much at the heart of this growth to simplify mantra, making sure that we focus the organization down on those capabilities and investment themes where we have leadership, and thereby making the company not only more focused but with it more predictable, more reliable, but also making it more profitable and more attractive for our shareholders, perhaps easier to understand as well. So all of that sits together. I think talking to the comment that Simon just made, both – actually I shouldn't say both anymore. The integration team is incredibly excited about making this work. I know that both our chairmen have been recently at the dedicated integration office and both were struck by the fact that these people are working for the combination. They're not two teams coming together trying to figure out what to do next. And that's exactly the trajectory we want to be on. We want to be absolutely ready for day 1 and we want to be ready also for day 30, 60 and 90, and that's what they are planning for. Thanks for the questions, Thomas. Can I please have the next question, operator?

Our next question comes from Rob West from Redburn. Rob West - Redburn (Europe) Ltd.: Hi there, thanks very much for taking my questions. Simon, you asked at your peril about questions on the P&L, so I'm going to give you one. Just looking at the production manufacturing expenses, which is the real key cost line I always look at in the quarter. So if I take 3Q this year versus 3Q last year, it's about $4.9 billion in both quarters. And if I look at the downstream, same line, about $2.6 billion this quarter and about $2.6 billion in Q3 last quarter. I'm wondering is that a little bit unfair to look at those and say the costs are broadly flat. There are moving parts in there like restructuring effects that are relatively one-off, that the underlying trend is going down a little bit more. Second question is on production, which I thought was good in the quarter. Is there some – you alluded to this in the release – some higher uptime at your fields go into that effect? So I think you mentioned Gulf of Mexico on the call and held GTL and Malaysia in the release, but is it a general theme that you can finally can squeeze more oil out of these fields across the entire company? I'm interested in that. And then maybe one more on just something you said a second ago, which was just there's some confidential information that isn't flowing between yourself and BG yet. Would that include the terms of your LNG contracts? Thanks. Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Rob. Probably I better take them all here. The last one is easy. Yes, it does because we can't talk about LNG commercial contracts until we are one company. There may be a point at which a clean team is established to insure that on day one we can operate without competing with each other, but that's for the future. Can we squeeze more barrels out of the assets? I'll take the questions in reverse order. The basic answer is yes. Several years ago we put quite some time and resources into what we call WRFM, Well and Reservoir Facility Monitoring, which in essence is how much more can you squeeze out from regular but small investments, sometimes as OpEx, sometimes as capital, from a reservoir. So upgrading, the monitoring of individual well pressure, performance, et cetera, and applying a bit of technology where appropriate, drilling extra wells, workovers. And over time that has indeed we believe squeezed more out of the assets. Our actual underlying decline rate this year has been around three percentage points. Five years ago that was usually 4.5%, even 5%. Now there's a maturity of assets contribution as well, but by and large we are taking probably 2%, 3% over the last couple of years more production out of the same asset than we would otherwise have expected. The expenses, you have to always look at the P&L at your peril. In general, the right comparison is more the nine months than the three months. The three months does include in some of the expenses you note the provisions made around Carmon Creek in particular, because they show up not in exploration but in production, potential production, manufacturing or SB&A expenses. So there are some one-offs in Q3, but the nine-month comparison where, for example, the production manufacturing are down by $2 billion, SB&A down by $1.5 billion, is more representative of the reductions that we've actually made. Ben van Beurden - Chief Executive Officer & Executive Director: Okay, thanks, Simon. I can't resist actually adding a comment on the second question. So on a quarterly basis, we come together, the upstream teams so – Andy Brown, Marvin Odum, Harry Brekelmans together with a few other people in a war room here in The Hague to just see how we are getting on with all the programs and all the assets and what we are seeing as results and where we see where the uptake of some of the excellent initiatives are working out and where we can do more. I join it every now and then. I just joined it a few weeks ago and we had another one of those sort of spend another three hours with them to see how things are picking up. It's remarkable to see how that focus on production excellence, so WRFM, as it was mentioned by Simon, really is beginning to come true and is transforming the quality of the operations. The reason why I'm so interested in it is because many of the concepts that we have there are concepts in terms of asset management at their highest work very, very well in the downstream, have worked very well in our LNG plants. The reliability of course is basically what you sell, reliability of supply, and of course also in our GTL plants where we have very, very complex assets that are very easily of course affected by unreliability. So, yeah, I do think that we are making a lot of progress there and I do also think that it is sustainable. Anyway, thanks very much for the question, Rob, and let's go to the next one. Operator?

Our next question comes from Aneek Haq from Exane BNP Paribas.

Hi, guys. Thank you very much. Just two questions, please, as well from me. The first one, coming back to this point on CapEx flexibility. I wondered if you could maybe – I understand obviously you can't talk about Shell-BG combined, but on Shell standalone basis, if we take that $30 billion number and were just say theoretically to assume no sanctions over the next couple of years, how much can you bring that down or how much of that roll off over the next few years? Is it $5 billion, is it $10 billion-ish? And then the second point on downstream actually. I'm just interested if we take that $2.5 billion-ish CCS earnings you've done this quarter, how much would you classify of that say as defensive, and I mean lubricants, I mean marketing, growing, etcetera, as well? Thank you. Simon P. Henry - Chief Financial Officer & Executive Director: Thanks, Aneek. CapEx flexibility we usually give numbers of something like 10%, 30%, 50% in terms of flexibility looking forward at this time of year, 10% next year, 30% 2017, and 50% in 2018. While I have to say they were non-scientific when I first used them, they've stood the test of time, so that's not unrealistic in terms of total flexibility that there may be. That's neither a projection nor a forecast. It's just a measure of the likely flexibility. And we will take decisions going forward. We have some interesting ones, for example, in chemicals over the next year. So it's not just massive upstream projects like (1:03:11) in Canada LNG that we need to think about. Is it possible just to repeat the second question, because I wasn't quite sure I understood it?

Yeah, just in terms of downstream, I'm looking to understand how much of the earnings you would classify as defensive, so not exposed necessarily to refining margins. Simon P. Henry - Chief Financial Officer & Executive Director: I've got it. Understand that I wasn't quite sure what defensive meant. We said before, and I wouldn't give too much of a preview, but there's a chance next week John Abbott will be presenting at the Investment Day. So talk to John further about this, but typically we have businesses, marketing, chemicals, trading and supply, and manufacturing. The first three are essentially what we term ratable income, i.e., consistent enough to rate that easily on it. And the manufacturing tends to go from a negative to a positive. Of the $2.6 billion or the $8 billion so far this year, more than half of it is what you term defensive, we might term ratable. And the manufacturing is doing well and I would note that because of the way we changed, or Ben changed, the accountabilities for the value chain in the downstream, putting a much greater emphasis on the integrated value from customer back through to crude, using the trading and supply organization and different accountabilities to maximize, we are capturing quite a lot more of the available margin than we would have done three years to four years ago. So we're not just benefiting from better industry refining margins. We're capturing more of them as well. Ben van Beurden - Chief Executive Officer & Executive Director: Okay. Thanks very much. Thanks for the question, Aneek. Can I have the next question, please, operator?

Our next question will come from Anish Kapadia from TPH. Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP: Hi, yes, a couple of questions for me as well. Just getting back to the cash flow and looking back over the last 12 months, it seems like you had a big contribution from working capital over that period. I just wanted to kind of think about it more on an organic basis, pre any working capital impacts. And when I look at it like that, it seems like your organic cash flow pre-working capital, post-interest, is around $15 billion or so less than organic CapEx and the dividend. So I was just wondering in terms of kind of just incurred, so kind of $60 world, do you think you can organically meet that kind of cash flow – sorry, meet the dividend and CapEx through cash flow over the next few years? And I was thinking Shell standalone. And then the second question, going back to Carmon Creek. Just wondering the decision to hold that project, just wondering is there anything to be kind of read into that in terms of the new government coming in in Canada, the potential for carbon tax and kind of issues in terms of carbon going forward becoming a kind of bigger issue for Shell overall, and could this be a precursor for Shell pulling out of oil sands altogether? Thank you. Ben van Beurden - Chief Executive Officer & Executive Director: Thanks, Anish. Let me take the second question first and I'll ask Simon to take care of the first one. No, the short answer to it is no. It would be, if you want to take an investment decision on a project and decide the fate of the project knowing that it will have to live for 30 years, 40 years, maybe in this case more than 50 years, you cannot let that decision be governed by the government of the day. And of course when it comes to carbon tax, yes, we know that this is an issue that we could face and that's exactly the reason why we price carbon into the economics of our projects. Even if there is no carbon price at this point in time or there's no carbon tax, we basically burden all our projects with a carbon price in order to make them future-proof for the scenario where a carbon price could materialize. So there is nothing else to be read in this. In terms of oil sands, no update on the portfolio there other than to say that the oil sands operations are actually pretty strong. If you look at the mine, it again significant cost takeout, significant reduction in ongoing capital commitments, and altogether a cash cost of about $25 a barrel, and that is at this quarter's environment. So it is actually quite, from a cash perspective, a very, very good contributor, so there's nothing much else to say about it. Simon, on the organic cash flow argument? Simon P. Henry - Chief Financial Officer & Executive Director: Sure. As I mentioned to Lydia earlier, the working cap does have some issues in there that are not what we might call working capital. It is not a straight adjustment, and we also have a knack of structurally reducing working capital you see if you look over a longer period. Just stepping back, our aim is to finance the dividend whatever the actual oil price is. In the medium to long term, we have flexibility around the investment level. We always – we've averaged $5 billion of divestment for quite some time now, probably the best part of a decade per year. It's not to be forgotten in terms of how we balance the books, and we intend to do more than that, double that, in fact, at the end of three years following the combination with BG. The other factor that we need to note is that investment level, capital investment intensity, tend to be correlated with the oil price. In fact, the correlation r-squared is 0.9, or 90% correlation, but we know that investment level in the industry and the unit cost will reset over time. They don't reset in three months but they do in three years. It is happening at the moment and, of course, how do we get from here to there. You start with a strong balance sheet and our balance sheet, 12.7% gearing. We've managed to cover the dividend over the past 12 months of $60 because we thought that the actions some time ago were necessary. We are planning lower for longer. You are aware of that, and our aim is to ensure that we protect that dividend whatever the actual prices turn out to be. Ben van Beurden - Chief Executive Officer & Executive Director: Okay, very good. Thanks, Simon. Operator, can I have the last question, please?

Our last question today comes from Biraj Borkhataria from RBC.

Hi, thanks for taking my question. On the U.S. resources business, I was wondering if you could just give us a quick reminder on what you've done in the last six months in terms of activity levels, and assuming $50 to $60 over the next year, whether you need to decrease activity levels further? Thanks. Ben van Beurden - Chief Executive Officer & Executive Director: Simon? Simon P. Henry - Chief Financial Officer & Executive Director: Well, we reduced investment below $3 billion. In fact, it's close to $2.5 billion at the moment. We're active in the Permian, in the Marcellus, the Utica, in West Canada in the Groundbirch and in the Duvernay liquids play and in Argentina. We're effectively running at sort of a care and maintain with the possible exception of some of the Permian activity at the moment. If the operation stays where it is, we will benefit because we're taking costs out on almost a daily basis, particularly away from the well pad. At the well pad we are pretty competitive today, and in our evacuation costs getting the molecules to market we are reasonably competitive as well. But there is a cost away from there that we are still working to take down. If the oil or gas prices were to recover, I'm not sure it will be top of our list of things to immediately spend more money on. Ben van Beurden - Chief Executive Officer & Executive Director: Okay, good. Thanks for that, Simon, and thanks to Biraj for that question. So that pretty much brings us to the end of this session. Thank you very much for all your questions and for of course joining the call. I'm very much aware that there is a number of calls going on more or less at the same time. Just a final reminder we have our Management Day in London next week on Tuesday, and then on the 4th of November, so the Wednesday, in New York. And I look forward to seeing many of you there. Thank you very much.

This concludes the Royal Dutch Shell Q3 results announcement call. Thank you for your participation.