Welcome to the BP presentation to the Financial Community, Webcast and Conference Call. I now hand over to Jessica Mitchell, Head of Investor Relations.

Hello and welcome. This is BP's third quarter 2016 results webcast and conference call. I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Chief Financial Officer, Brian Gilvary. Before we start, I need to draw your attention to our cautionary statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our UK and SEC filings. Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website. Thank you. And now over to Brian.

Thanks, Jess. Welcome everybody and thank you for joining us. Today we are here to report on our results for the third quarter. As you have seen, the environment remained volatile over the quarter and continued to impact quarterly earnings across the sector. Outside of the environment, we had some mainly one-off and noncash items impacting our Upstream results for the period, while our Downstream delivered strong underlying earnings. Most notably, it has been another quarter of robust underlying operating cash delivery for the Group. This clearly demonstrates the resilience of our business operations to the current environment and the impact of our ongoing work to reset the company. We remain confident in the progress we are making to reestablish the balance in our financial frame and reposition our businesses for today's environment. We will begin by looking at the macro, then cover our third quarter numbers in detail before updating you on our financial frame and the progress we are making towards rebalancing in 2017. We will finish up with a brief update on our businesses before Jess and I take your questions. So, looking first at the oil market. Our view on the fundamentals remain largely unchanged. The physical market appears to have moved broadly into balance with the amount of oil produced each day broadly in line with daily consumption. Nevertheless, oil inventories are at record levels and will still take some time to reduce. Looking ahead, we expect inventories to decline gradually next year supported by continued demand growth and sustained weakness in non-OPEC supply. The precise pace and timing of that decline will depend on the outcome of OPEC's meetings at the end of November. Forward prices for Brent continue to point a modest upper trajectory. The forward curve moved slightly higher in October following…

Well, welcome back everybody. We would like to take the first question from Oswald Clint at Bernstein. Are you there, Oswald?

Yes. Hi. Thank you, Jess. Good morning. Yeah. Maybe the first question, Brian, just on the U.S. onshore gas business with gas prices up at closer to the $3 level in the third quarter. Can you talk about the underlying profitability of that business given you have such a large kind of natural gas business there, please? And then secondly, maybe just following up on your comments on the restructuring continuing through 2017. Perhaps you could explain why that has to continue for I guess another 12 months, please. Thank you.

Thanks, Oswald. In terms of Lower 48, we're now running about five rigs the last time I looked, in terms of where the activity is. We're continuing to reduce costs in that business, which is bringing the breakeven prices down. The key is really about what we learn about technology and how we run the business. We run it with a different financial frame to the rest of the Group in terms of how it's managed. And it is continuing, as you'll see from the various quarterly numbers that we now start to release, get to be more and more profitable going forward. And of course, helped somewhat this quarter by the prices as the prices have come up. So, Lower 48, it really is about testing new zones, looking at innovative well designs. It's really experimenting with that business and getting more comfortable with how we run the Lower 48 and reducing costs over time and the amount of capital that's going in. But today, it's running about five rigs, I think the peak last year is around 11 rigs or 12 rigs we had at one point. In terms of restructuring, we've extended it out to next year, mostly because of the activity as we've got more and more underneath simplification and how we're driving efficiencies into the business. We now can see that actually there's likely to be more restructuring into next year. Very confident now around the $7 billion target. We've talked about $6.1 billion at the end of this quarter. I think we'll see further significant progress through the fourth quarter. Very confident we'll hit the $7 billion for next year. We'll probably hit that early. And then, it may well be that the costs go beyond that as we look at this next phase of restructuring programs.

Super. Thank you.

Thanks, Oswald. We will take the next question from Irene Himona at Soc Gen. Irene Himona - Société Générale SA (Broker): Thank you, Jess. Good morning, Brian. I had two questions, please. Firstly, in Q3, your natural gas realizations outside the U.S. appear somewhat weaker than anticipated perhaps. Can you give us any sort of guidance on how the portfolio outside the U.S. is linked, OE versus Hub prices perhaps? My second question, just if you can remind us on the Gulf of Mexico cash payments, it was $2.3 billion in Q3. What can we expect going forward as the annual or quarterly run rate into 2017, please? Thank you.

So, maybe just picking up that last question, first. We've got a schedule we've put out there from all the various settlements, from last year 2015 and from the criminal settlements back in 2012. So, there are specific payments in certain quarters going forward, and I'm pretty confident that we put that out in the website before. So, if we haven't got that to hand, we'll make sure that gets out to you, Irene. But that's out there publicly available in terms of – I think we did it at last quarter's results and the one before that. The only uncertainty will really be around how the payments that go out associated with the class action lawsuit settlement, the PSC settlements, particularly business economic loss claims. We are accelerating in a number of those at the moment. You will have seen quite a few go out recently. We also resolved a lot of private claims through the second and third quarter of this year, which you will have seen come out in the payment schedules. They are likely to run down over the next couple of years, so they are the only things where there's any uncertainty. But now we're into sort of final stages of that fund, I think we're down to from the peak on business economic loss claims, I think we had a 144,000 claims at the peak of which now we're down to 25,000 claims, or 35,000 claims including the daughter claims which is, i.e., claims linked to the original claim. And they are being processed at a fairly rapid rate right now in terms of the facility. So, there are a series of schedule payments around settlements, they are available. They should be on the website or we'll certainly get those to you. Then the…

Thank you, Brian. Okay. Our next question from Brendan Warn at BMO.

Yeah. Thanks. Good morning, Brian. Good morning, Jess. Just a question if I can circle back to – I think it relates to slide 16, and you made comments about share buybacks or balancing your scrip. Can you just talk through, obviously, if you assume prevailing prices, can you just clarify that if by 2020, if we're still in sort of prevailing prices, just in your mind what would be the trigger for share buyback? Would you comfortably to be able to move to, call it, mop up the extra scrip that's been issued, and just in terms of how that ranks ahead of any further growth acquisitions, please?

Thanks. Yeah. So, once we get through 2017, we're now confident in terms of our plans that we'll be balancing at the prevailing oil price next year. Let's assume around $50 to $55 a barrel, but we're now confident that we'll get operating cash balanced that with CapEx and dividends for next year. That looks pretty much within sight now. So, in terms of what we laid out for you earlier this year at the back end of last year, we're confident we'll get there. Once we get back into balance, then I think within the financial frame we've got full flexibility to look at other options, whether they be of an inorganic nature in the capital space. But certainly, buybacks would come on to the radar screen. To the degree that we have been issuing scrip, of course, we would like to offset that. We don't like to dilute our shareholders. So, when that opportunity arises, that's something we'd look at. And it'd really depend on where we are, where the prevailing market is. You'll recall when we did the transactions around TNK and Rosneft, we bought back $12 billion of stock, actually it was $10 billion, two tranches, $10 billion and then $2 billion. So, buybacks are definitely in the armory. Obviously, as we've gone through 2015 and 2016, it's been really about – focused about rebalancing with the big drop in oil price from $110 down to $28 at the low point. So, once we got things back into balance next year, then buybacks will definitely come back inside the frame. And it will be the sort of broader frame of options around long-term sustainable dividend growth, buybacks and other potential inorganic opportunities that may arise.

Okay. Thanks, Brian.

Turning now to Anish Kapadia of Tudor, Pickering, Holt. Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP: Good morning, Brian. Yeah. A couple of questions, please. First one is on your cash flow, just trying to bridge where you are at the moment to the guidance for 2017. So, if I look at your Q3 cash flow, stripping out working capital and I suppose normalizing the Rosneft dividend this quarter, it's about just under $4 billion, I think, for the quarter. So, about $16 billion on an annualized basis in a $45 oil price environment. Based on your breakeven guidance for next year, it suggests about $22 billion plus of cash flow in a $50 to $55 oil price environment. So, I was just wondering if you could bridge the gap between that $16 billion to the $22 billion-plus? Obviously there's some oil price in there, but what the other elements that take you up to that level? And then the second one, the – in a kind of sustained $55-plus environment next year, I know you have your CapEx range, but what's the short cycle CapEx opportunity that you have? How much capital could you put to work in a kind of $55-plus and say a strong gas price environment if the opportunity arose? Thank you.

Okay. On the first point, so, that's actually not – I mean, one as I've already said before, even when we had the $32 billion target, never take a quarter times four. That's not – especially this quarter. So, but broadly, broadly, you would look at the operating cash for this year, you would take out further costs that we would expect to come through at the back-end of 4Q along with what else is to come out next year. You'd have the restructuring cash payments around ratex (37:50) that goes out this year that you wouldn't have to repeat next year. So, if you like, cash flow this year has a weight of payments associated with that ratex (38:00), that $2 billion restructuring charge that we talked about. And you've also got growth in margins and volumes to come through along with, as you pointed out, the environment. So, if you look at the average oil price this year, I think it's been tracking around $42, $43 a barrel so far year-to-date, which is actually roughly in line in what we set our plans at for this year. So actually, we've been sort of tracking not exactly each quarter but year-to-date we're kind of around where we expected to be in terms of the plan. We expected some firmness around the fourth quarter. We'll see what happens with OPEC at the end of this month, but I think $50, $55 looks a reasonable assumption coming into next year. And we're confident that we can balance at those, which means that, yes, you're right, the operating cash clearly would need to be north of $20 billion given the CapEx range we've given you and given where the dividend is. But we're confident that we'll get there one you strip out…

Thanks, Anish. A question now from Lydia Rainforth at Barclays.

Thanks, Jess, and good morning. Two questions if I could. Brian, you were talking, just in answer to Anish's question about the 2017 cash flow numbers, and just from the commentary it does sound that you're very confident around that $50/$55 number. Could you just talk about where – are there any sort of operational aspects in terms of the risk that you're seeing around that? Sort of, where are the sort of challenges in terms of getting to that number next year from the operational standpoint? And then, secondly, just quickly on Rosneft, and the sort of deals that they've done with whether it's Essar Oil or Bashneft. How does that fit with BP's strategy within Russia? Thanks.

Okay, Lydia. So, I'll come on to that second question shortly. But in terms of assumptions for next year, of course, we need to make sure that all the kit is running as well as it's run this year. Actually, I'm not even sure whether reliability figures for next year may actually be slightly below where we are this year in terms of – because we had a very strong year this year in terms of reliability and availability in Downstream. So we'll have relatively conservative assumptions for that for next year. We'll need to make sure the projects come on time, on budget, they're all proceeding incredibly well right now. If I look at the oversight that Bernard and his team has on those projects, they're looking on-track in terms of what we're expecting for next year. So, of course, they would have to come on-stream. We'd have to continue to see the performance improvements that we've seen in Downstream this year continue into next year and with a relatively conservative refining margin assumption. So, I'm not concerned that the plan feels overly stretched to get back into balance next year. We've set ourselves a target back in the fourth quarter of 2014 to give ourselves two years to get back into balance. We're confident that we'll do that now around the assumptions that we've laid out for next year. And it will assume the oil price is around $50, $55 next year. In terms of Russia, yes, you will have seen the announcements around Bashneft, which is an acquisition of one of the state companies in Russia, where Rosneft acquired 50.1%. We'll, of course, consolidate that into our results as that transaction gets closed. So, that will be about – if you look at – so, from BP's…

That's very helpful. Thank you.

Over now to Jason Gammel at Jefferies.

Good morning, everyone. Two questions for me, please. First of all, Brian, I apologize if you've made this explicit, but I've missed it if you have. On the $50 to $55 breakeven price, does that assume that the entire dividend is paid in cash, or is there a scrip component of that? And then the second question is on the Fuels business on the quarter, the flat results sequentially struck me as quite resilient just given the refining margins declined in the quarter and availability ticked down slightly. So, can you help me to reconcile what the offsetting factors were there? Is that simply stronger marketing operations, and was there a contribution from the trading business in that result?

Yeah. So, on the first question, we've set out that we would get things back into balance including the full dividend. Now, for next year, the scrip uptake over the last – since we introduced the scrip in 2009, has been around about 18%. It's been high this year which, of course, has helped our cash position, hence why we would be keen to be able to offset that dilution going forward as we get back into balance. So, the new financial frame we have is that operating cash needs to cover the full dividend along with organic CapEx. For next year it's likely that we'll need some help from the scrip uptake as we get through this transition of having a full year of all the costs and restructuring charges out which would be 2018. But we're confident for the next year on a cash basis we'll certainly get back into balance. In terms of the Downstream result, I think it just reflects all the work that Tufan and his team have been doing in terms of – and we've talked about this in previous quarters is how do we create resilience, and there's a slide that Tufan has used on previous quarters that will show you how the refining margin has declined and yet how our earnings have increased over a period of time, in that what has been structured inside the business is that through the Fuels marketing business and growing that business going forward they've been able to create a balance within the overall portfolio, of course, coupled also with the Lubricants and to a less degree, the Chemicals business. So, half of the earnings coming out of the Downstream now are not as exposed to that refining margin, which is what we laid out in our presentation. So, I think what you're seeing this quarter in Downstream is the strength coming through that Fuels marketing result in what was a relatively solid trading result for the quarter, but certainly nothing out of the ordinary. So, actually it really is coming through from the Fuels business.

Very helpful. Thank you, Brian.

Thanks, Jason. Now from Jon Rigby at UBS.

Yes. Hi, Brian. Can I ask two questions? The first is on the $6.1 billion cash cost performance. Are you able to break that down a little bit and sort of characterize where it's coming from. I think from memory that the Downstream was ahead of the Upstream in terms of contribution when we last revisited it. So, are you able to deepen a little bit on the analysis on that? And the second is, I know it's somewhat frustrating I guess for you as everybody else is – where you take sort of big noncash exploration charges which hurt your earnings. I know there's no economic impact. But as you sort of wind down or normalize your exploration activity and go through the sort of backlog of stock that's still under appraisal, is there very much more to come in that, or will we start to see the exploration charge in the quarters begin to sort of level out closer to the kind of level of activity that you're actually now running at from a cash basis? Thanks.

So, on the cost question, it's actually neck and neck now, Jon. It's exactly the same. So it's – in the $6.1 billion, just over 40% is – actually it's about 45% has come out of the Upstream, 40% – 45% out of the Downstream and the balance out of corporate. Now, of course, some of the corporate costs already sit in the two segments, but they're exactly the same in terms of the delta on the $6.1 billion. There is still a big chunk yet to come through in the fourth quarter and into next year, which is really around the final Upstream plans. But equally Downstream has still got further restructuring plans in place. So, they're about the same in terms of sources. And I think that's just symptomatic of how we've driven efficiency and reorganization across the whole corporation. So, it's no surprise that it's about the same. But you're right. Previously, it was more driven by the Upstream than the Downstream, but it's about 50/50 now. In terms of the exploration piece, of course, because of – as we've gone through with the re-set of the company in the last couple of years, there is a big inventory of exploration intangibles that we're working our way through. And you're seeing that come through, if anything, it's actually reduced compared to the run rate that we were seeing only even a couple of years ago. There are still more decisions to be taken, we'll continue to do that on a point-forward basis. We'll try and give you more information around what that looks like around the fourth quarter results. But I can't, at this point, say, we've reached a sort of stable steady state. It – ultimately everything gets back to strategy, it's really about how we've reviewed what we're doing around exploration strategy. We're doing a lot less wildcats. There's a lot more focus now on the infield developments. As a consequence of that, you will see some of the decisions we've taken. So, the Great Australian Bight is a good example of. Ultimately, that was not commercial for the company. And if we stacked it up in the portfolio of options that Bernard and his team we're looking at, the Great Australian Bight simply didn't work, and, on that basis, we stepped away. We're still absolutely committed to Australia. It's not about that location and, indeed, actually, we announced a – from memory, we announced a license around North West Shelf, new access position we've taken in the North West Shelf. So, it's really about how we now sift and sort the portfolio of options we have. And as a direct consequence of that, some things we'll view as not being commercial going forward. And, of course, they get taken through to underlying earnings in terms of exploration write-offs. But I can't, at this point, Jon, say where we are in the cycle given the size of the intangible asset base that we still have.

Fair enough. Thank you.

Thanks, Jon. And we'll take a question now from Rob West at Redburn. Go ahead, Rob. Rob West - Redburn (Europe) Ltd.: I wanted to ask my first question about volumes. You already alluded to this in your comments, but it wasn't a particularly normal quarter. I was wondering, could you quantify, is there any disruption in the volumes, say year-on-year that you expect to come back as we look to future quarters? I note from the release that it might not come back in 4Q. You alluded to higher turnaround activity compared with the third quarter. I just wanted to confirm, is that right? It sounded in your comments that you said nine turnarounds had been completed. And so, I just want to confirm, are there more still to come? And then, finally, has anything changed in your mind about Alaska? The big LNG project there, just based on looking at it in the last quarter and some of your partner's comments. Thanks very much.

On volumes, no, it's a really good point. And so, actually, if you looked at this quarter, there was a lot of moving parts around the quarter on volumes. I think we said on line down 2%. Actually, if you take the Pascagoula outage that we had, which was over 20,000 barrels a day, weather impacts we're just shy of 20,000 barrels a day. And then we have PSA impacts primarily around Iraq. If you add all of those effects up, they come to just under 130,000 barrels a day, which actually explains that delta. So, you wouldn't expect to see certainly, the Pascagoula outage and weather repeat itself going into the fourth quarter. Notwithstanding, I think we're now getting towards the end of the hurricane season, or pretty close to it. So, you're right, most of those effects won't repeat through future quarters. So, that's why you'll start to see, and the turnaround, delta quarter-on-quarter, you'll start to see a little bit of impact of that. On Alaska, we still have the – there's still 30 Tcf of proved resources up there, in terms of gas. Yes. I understand the most recent comments that some of our partners have made. I think gas is a great opportunity for Alaska going forward, and for those of us that have lived the round and seen this project over many, many years, I'm sure it'll have more machinations going forward. But there is nothing firm at this point, in terms of where the point forward is, in terms of that state in the resource base. But it is a great resource base, it's discovered, we know it's there – it's being reinjected today. I think the short-term economics make it difficult. But in terms of long-term resource, it's – it may well be a great opportunity to bring to market. But right now, nothing is happening. Rob West - Redburn (Europe) Ltd.: Very clear. Thanks.

Thanks, Rob. Moving now to Theepan Jothilingam of Exane.

Thanks. Jess. Good morning, Brian. Two questions, please. Could you just come back to – I think you talked about the offsetting the Macondo cash out lays with disposals next year. So, could you just give us a little bit more confidence that can be achieved and sort of essentially a bit of flavor in terms of where you see disposals or disposal potential in the BP portfolio going forward? And then, secondly, just in terms of forward-looking growth, if you can give us a quick update on the two UK projects, please? Thank you.

Thanks, Theepan. So, in terms of disposal proceeds, we've set a target this year of $3 billion to $5 billion. We're already close to $3 billion at the end of the third quarter. We have a number of projects in train that will comfortably get you to the $5 billion over an 18-month period. So, some of those will flow into the first quarter next year. That will underpin $2 billion to $3 billion next year. A lot of the projects were looking at are Midstream assets. It's some of our properties that we own globally. You'll have seen that we announced the sale of our Sunbury assets, our property assets down in Sunbury recently which we've – gave probably significant proceeds. So, the proceeds side of this is well-underpinned in terms of $3 billion to $5 billion this year, $2 billion to $3 billion next year. And actually, you only – in terms of Macondo liabilities, the big lumpy years are this year with the settlements from last year that originally transacted this year, and the private settlements that we've managed to resolve, along with the payments next year. And then we get into a steady state of $1 billion a year. So, actually, you only need about $1 billion, $1.5 billion of disposal proceeds beyond 2018 to cover it. Although, we'll probably continue to churn at $2 billion to $3 billion. And a lot of that churn just comes out of looking at the portfolio as we take options to move certain commercial projects forward. Other projects within the portfolio may have lower returns and therefore, we'll look to move out of those assets. So, there will always be a natural churn in our business, there always has been of $2 billion to $3 billion, so absolutely confident…

Thanks, Brian.

Okay. Moving next to Thomas Adolff of Credit Suisse. Thomas Adolff - Credit Suisse Securities (Europe) Ltd.: Good morning, guys. I've got a couple of questions, please. Firstly, we're now just over two years into the downturn, and we haven't really seen BP do many bolt-ons unlike your partner, Rosneft. So, Brian, are you surprised by that? And particularly when we think about the comment you made at the end of 2014 I would have thought that BP would be a bit more active on bolt-ons. Second question, I guess, on franchise assets, and I'm referring to assets that define a company. Say, for Chevron, it will be the non-royalty paying acreage in the Permian. For Shell, it might be the Santos Basin in Brazil. What would it be for BP? And maybe a final one, a very short one, what sort of reserve replacement ratio excluding Russia do you expect for 2016? Thank you.

Okay. Well, let me take that last one first because it would be too early to say that. It really will be a function of the FIDs we put through this year. We've got three FIDs that have gone through already. We have two more. One of which you'll all be aware of, around Mad Dog Phase 2 which is coming up in fourth quarter. So, where we end up in terms of the underlying reserves replacement excluding Russia and our other entities, it's too early to say at this point. So, can't really give you indication around that. But that really is a function of FIDs and where we end up with the reserves at the end of the year. In terms of value options and bolt-ons, actually we've looked at a lot of activity. We've actually have bolted on one or two small things around the portfolio. We've actually deepened in some positions. But I think the thing that we've looked at as we've gone through last year and the second half of 2015 in particular, the valuations against some of the assets that we were looking at were simply too high. And in some respects we come back to previous question from Theepan, this really is not a seller's market for Upstream. And I think people's perception of the value they should be achieving are above what we would see as being economic or would be accretive to the company. So, I think we've always been clear. If a transaction is accretive and it's accretive to our shareholders, or it's BP strategic and adds value into the long-term for the company, then absolutely you'll see to do those things, and let's see what happens over the next 12 months. But I think there will be opportunities that…

Thanks, Thomas. We have a question from the web now from Jags Walia of APG. And he's asking, given the deflation you have seen, is it time to step up FIDs?

Yeah. Thank you. Well, so we've done three FIDs already this year. We had Atoll Phase 1, which is an early production scheme that we accelerated. There was a Tangier expansion and Trinidad Onshore Compression. And we've got two further ones which I just alluded to that we're looking at here in the fourth quarter. I think it's natural given where we've just come from. If you think – as I just said, in the previous question, we rebuilt the company over 2011 to 2014. The period 2015 and 2016 was really about restoring balance and getting things back into balance, the primacy in terms of supporting the dividend, and that was one of the prima facie priorities that we had. As we now look going forward, we're now starting to work our way through some of that back inventory of projects, and I think you'll start to see more FIDs come through next year. And, of course, we've also got the big series of new projects that come on stream next year that generate significant cash flow growth into the future. So, I think you'll start to see the FID start to ramp up next year with potentially five being completed this year.

Thanks, Brian. We'll take the next question from Martijn Rats of Morgan Stanley. Martijn P. Rats - Morgan Stanley & Co. International Plc: Yeah. Good morning. I've got two, if I may. In the past, BP has said that the head count in the Upstream was on a trajectory of falling from about 30,000 to 18,000. And I was wondering if you could quantify sort of broadly sort of where we are. Are we already approaching that 18,000 figure or are we still some way off? And secondly, I wanted to take you up on this comments about high availability of your Upstream assets. I think you mentioned a figure of 95% availability. And I was wondering how that compares to 2015 and 2014? And specifically, if there was any way of quantifying how much incremental oil you've been able to produce sheerly by higher availability, higher utilizations of assets that you already have? Essentially, extra oil production without any CapEx. Is there a figure for that?

Okay, Martijn. So, on reliability, I don't have the numbers to hand. But I recall back in 2014, I'm guessing for the portfolio, it was somewhere north of 85%, but south of 90%, just from memory, as I recall. If I think about some of the things that Lamar and Bernard, at the time, were focused on in terms of reliability, it was one of the key metrics we were looking at, and particularly in places like the North Sea. So I think they've made huge progress in terms of where we got to so far in terms of the third quarter. So, that was a great example of that. But I think it was running relatively around 85% to 90% from memory. In terms of head count, well, you'll see when we actually produce the head count numbers in the annual report and accounts for next year. But, the last I looked at, we were – if you exclude contractors, and I think that was – was your question excluding contractors or including? Sorry, Martijn. Martijn P. Rats - Morgan Stanley & Co. International Plc: Well, I remember Mr. Dudley saying at some point, from 30,000 to 18,000. And actually frankly, I'm not quite sure whether, at that point, he was talking about excluding contractors or including contractors. I think it's including contractors.

If you include contractors that would be the 30,000 figure. And that is certainly tracking at the end of 3Q, we're down to the sort of low 20,000s. And in terms of our own workforce, we're down at nearly 18,000 at the end of the third quarter. So, quite significant progress already, and that's why you're seeing some of those cost benefits come through. Of course, there's a ratex (65:01) payments associated with our own employees over that piece, so that will take some time to work its way through the system into next year. Martijn P. Rats - Morgan Stanley & Co. International Plc: Okay. That's very useful. Thanks.

Thanks, Martijn. Now a question from Iain Reid at Macquarie. Iain Reid - Macquarie Capital (Europe) Ltd.: Hi, guys. Brian, just a couple of questions. On Brazil, I see you've taken a write-down of the Devon acreage. I presume this is just the exploration part of it. I'm just wondering what your kind of appetite for Brazil activity is? We've got a license round coming up next year, which has got some kind of off block extensions of existing fields. Just interested in your appetite for that? And secondly, on the rig cancelation number, can you just tell us what that was? And how are you in terms of your rig fleet at the moment? Is there more of this coming or are you kind of happy with the kind of quantum of rigs you've actually got under contract right now?

Okay. On Brazil, yes, you're right. It was around the Devon acquisition; it was the South Campos, it was one of the specific blocks where we had a non-commercial option discovery going forward. So, that's effectively what that write-off is about. And that actually – we've written off other assets associated with that acquisition as well. So, I think it's fair to say we haven't yet unlocked the value that we were anticipating or certainly around the original investment we did into Devon for that piece. Although there are other things that came with the Devon acquisition in other regions like Gulf of Mexico where we've seen better progress. So, no, we haven't seen anything come out of that really yet out of that Devon. Although, we still have a couple of commercial prospects associated with that acquisition that we're still sizing up. In terms of next license round, it would have to stack up commercially against everything else that we're looking at. So, we're still in Brazil. I think if the options are sufficiently attractive compared to our alternatives, then they'll rank in that space. But – no, Brazil we're still there, we're still on the ground, and it really – your question, where commercially the options stack up versus everything else. And then, sorry Iain, your second question was around? Iain Reid - Macquarie Capital (Europe) Ltd.: Yeah. The rig cancellations.

Oh, rig cancellations. Iain Reid - Macquarie Capital (Europe) Ltd.: How much was that in the quarter?

Yeah. Iain Reid - Macquarie Capital (Europe) Ltd.: And what about your fleet going forward?

Yeah. So, for the quarter, it was $90 million higher than the previous quarter. So the delta between the two. And, actual – the actual cost was north of $150 million for the quarter. We've worked our way through now the whole fleet. I think, in total, we've had four rigs we've cancelled so far, with a small number we put on standby. But, again, it's really as the team work their way through the inventory of activity we have going forward we'll continue to optimize. So I can't say at this point that we're finished with rig cancellations, but as activity ramps up next year, it's really around that team that optimizes the rig fleet globally, we'll determine whether commercially the right thing to do is run with the rig or, in this case, we chose not to. And that was the right commercial economic decision to take, and we will continue to do that on a point forward basis. Iain Reid - Macquarie Capital (Europe) Ltd.: Okay. Thanks a lot.

Thanks, Iain. Next question from Lucas Herrmann at Deutsche Bank.

Yes. Thanks very much. Brian, morning. Just a couple or two or three if I may. Brian, just getting back to a question Anish asked you around your annualizing quarters, and you essentially said you wouldn't. But you also said especially this quarter. I wondered why, especially this quarter, what are the things that we're perhaps not seeing in cash that you can see? Secondly, sorry, just going back to Macondo and the cost this year. Can you just remind us whether – I know you have provided schedules, but the schedules detail annual payments, and we're stuck with quarterly reporting? And I just wonder where the $1 billion or so that was supposed to go out to the states and the short $600 million that was going out to wildlife and others has actually flowed already or whether that's due to flow the rest of the year? So really, I guess, a break between how much of the outflow is BEL and how much of the outflow is other. And finally, post Aker BP, how much operating income did you forego in Norway effectively this quarter relative to last?

Well, that last question will definitely test my skill base and memory, so we may well have to come back to you on the last one. Norway would have been a sub-segment even deeper below than where I would look. I'd have caught it through the whole North Sea. But we may have to come back to you on that one, Lucas.

No worries.

On – let me take the Deepwater Horizon payment schedule, we will come back to you, actually. We'll probably put a schedule up on the website. It will be easier for everyone to see what the actual – to agree that things are settled and we know when the payments are going out like the state claims, like the civil penalties, like the criminal penalties, all of those things are locked in and with dates of when those cash payments go. So, we'll come back to you with that. There were significant payments went out in the second quarter and third quarter around a raft of settlements around a big chunk of private claims that we took out outside of the settlement, and they were taken care of through the court, and through a specific process that we had. And then other costs like, for example, MDL 2185 that we don't talk a lot about, but we also settled that in the second quarter with a payment of that going out due this year. So, we'll come back to you with that, if that's okay, Lucas, in terms of specific payments.

Sure.

And then in terms of annualized quarters, no, the only reason why I said this quarter is if you took $4.8 billion, you could back out the working capital, you may well find that sustainable going forward. You sort of know what the answer needs to be somewhere around $22 billion, so sort of 4 times 4 doesn't work for you. So I wouldn't use this quarter. If you're going to do a simple four times, you need one with $5.5 billion in it.

I'm sorry. Just clarity on guidance, on cash flow? You don't include working capital moves in your assumptions on operating cash and coverage of CapEx and dividends going forward do you?

No. Unless it's sustainable. And – I mean, yeah, there is a program in both, especially a program that was ramped up actually over the last eight quarters, to get sustainable working capital out the system. And one of the biggest areas we have, where we have float movement is around our trading barrels that we use, which logically, you could say we're actually, is cash and inventory because you could liquidate those at any point in time. But that's not something we've gone through at this point. It's one of the things that we'll be looking at going forward. But no. Only to the degree that it's sustainable, we'd then build that into our cash flow projections. So for example, if you sell out a refining system, that working capital is gone forever.

Yeah. Brian, thanks very much.

Okay. Thank you. Turning now to Biraj Borkhataria of RBC.

Hi. Thanks for taking my questions. I had a couple on the U.S. onshore business. The CapEx in that business seems to be quite volatile from quarter-to-quarter, and this quarter was particularly low. I was wondering if you could give a bit more color around what is driving that? And also what is a sustaining CapEx number for that number to hold production flat over the next year or two on an annual basis? And following on from that, can you talk about any service pricing pressure you're seeing in the U.S. onshore business? Whether or not you're seeing it? Thanks.

Well, I'll be seeing Dave Lawler later this week. So, I'll find out more then about kind of what he's seeing about – I don't have that to hand here in terms of what he's seeing in terms of services costs. There is some ramp-up in the rigs, particularly for the industry around the Permian as the prices have come back up around some of the horizontals. You are seeing some rig activity come up. But I'm not sure that we're seeing anything on the service side other than what we've already driven through. On CapEx, it's down 63% year-on-year, which is completely driven by the planned investment schedule that they have, that the team had. So, they went through a period, where they did a series of experiments around particular types of activity, around multi-laterals that they ran. That's taught them a lot about some of the reservoirs. And actually in actual fact, they are going to start revamping up and restarting investment in the third quarter. So you'll start to see some of the CapEx ramp up. In terms of a point forward capital for that business we'd really have to come back to you with a figure on that. But I would think something around $0.5 billion, or north of $0.5 billion is what you'd expect going forward. I think when we first put the frame in place, we had up to $1 billion of capital allocated. But, again, it's really a function of what are the options for us. That's a great short-term option that if we had to ramp activity up quickly, let's say, because of prices or because we have discretionary capital that would be an obvious place where you'd start to do it. So, it can take some of the float in terms of options for us depending on what's happening in the short-term. It's a great way in which in terms of getting short-term paybacks and high returns. And the more and more we learn about that business and the way in which it's run, I think the more value we're going to bring.

If I could just then follow-up on Macondo as well, just to clarify some of the earlier questions. If I add up all the moving parts for 2018, I'm getting to a figure of about $2 billion cash outflow. I know it'll probably be on your website later. I was wondering if that is a sensible number to assume for 2018?

That is pretty much spot on with what I have in the forward plans. Notwithstanding any other assumptions we have around where we are around any of the de minimis type claims that might be out there. But in terms of materiality, something around $2 billion is a good number. And, actually, just since this question keeps coming up, it's going to be for this year, the total cash out payments will be anywhere from $6 billion to $7 billion. For 2017, anywhere from $3.5 billion to $4.5 billion, and there are ranges around these. And then once you get into 2018, it goes into $2 billion, and then in sort of 2019 onwards it's sort of $1 billion to $1.3 billion dropping down to $1 billion at the end of the piece.

Thanks. That's very helpful.

We will get a schedule out there for you though. I mean, all those settlements feel like an awful long time ago now. But we will get those schedules on the website so you can see them.

Great. Thanks.

Thanks, Biraj. A question now from Alastair Syme of Citi.

Thanks very much, Jess. You've got on the notes that you've lowered some of your long-term oil and gas price assumptions as you've re-done your views this year, and I think also the discount rate. So, can you talk a wee bit of what's going on and also the drivers of the impairment reversals? And then secondly, you've mentioned a couple of times the Mad Dog 2 FID. What exactly are you seeing in terms of accelerating or deepening inflation – or deflation in the offshore? Thank you.

Well, Mad Dog Phase 2 it's sort of imminent, I guess. We're right here in the fourth quarter now, we're right mostly ready to FID. I think our partners are likely to do that in the first quarter next year. So, this is maybe slightly out of sync. But I think the project is pretty much there now. It's significantly below even – it's certainly below the $10 billion that we talked about. And now, it's sort of drifting to a number significantly below that as well. So, I think that's ready to go. And now the key is it gets delivered at the sort of new cost set that we have, as I mentioned that Bernard and the team have got right now in terms of where that's got to. On price assumptions, yes. No-we've just done, and you will have seen from the energy outlook that we put out there, our new set of long-term price assumptions. We effectively move to $75 real for oil in the long term. And in terms of impairment, we take the current price today and then smooth it up to that level after 2022. And gas, we moved down to $4 real in terms of those impairment tests. We also looked at the whole range of all of our discount factors and other metrics that we reviewed as we do annually in this quarter, and that reduced the discount rate down by a factor. And then along with running that, that then created a trigger for all of our consolidated units in the Upstream, and that's why you're seeing these impairment write-backs come back this quarter. But that's just purely a function of running those models.

But Brian, any particular reason why Angola and North Sea would feature more predominantly in those impairment reversals?

No. Not specifically, other than the size of the assets, what the reserves positions looks like, but it really is a function of once you have the trigger to go and look at them, and we've looked at them a number of times over the last couple of years, we've had a couple of triggers on Angola and North Sea before. If you now run the new set of prices assumptions, that's where those carrying values come out. It's a pretty rigorous process, it's very transparent, we run it every year, and it's led to those write-backs this quarter.

Great.

I should also say that there's a lot of moving parts in that number. And since we went through all of the consolidated units, there were some positives and negatives right across the piste. The net position is what you saw.

Great. Thanks Brian.

Okay. We'll take the last question from Chris Kuplent of Bank of America.

Thank you, Jess. Brian, just two quick ones. Of your exploration expense, which came in for the quarter at around $800 million, can you just confirm how much of that is in your non-operating income, and how much is actually flowing through your reported underlying Upstream? I think you've specified the Brazilian write-off, but I just wanted to see the total number. And any comment you want to give us on a sort of run rate as far as underlying exploration expenses are concerned. And lastly, wanted to check how you're feeling about your Indian options in terms of future FIDs, not necessarily in the next six months, but any latest developments that you can report from there? Thank you.

So, I assume you're talking exploration write-offs when you say exploration expenses?

Yeah. Correct.

It's the biggest – the biggest thing that you saw coming through in that quarter was actually the delta off the Brazilian asset that we talked about earlier, then lots of small pieces. But we're getting to a sort of stable steady state number going forward. But you had a figure, you mentioned $800 million?

Yeah. That's for the third quarter, what you call exploration expense, of which there are 687 exploration expenditure write-offs. But I wondered whether you had to hand a breakdown of how much of that has gone through your non-operating...

Oh. I'm sorry...

And how much is reflected in underlying...

Yeah. Yeah. So there's also – so we'd need to come back on the specifics. But there's over $300 million of NOIs hit that number as well, which also relates back to the Devon acquisition. So, it's about, from memory, it's somewhere around $330 million, $340 million of that is NOI.

Right. So, if I take that off for the $800 million mark, then we're still left with more than $500 million reflected in your underlying Upstream earnings, yeah?

Correct. That's correct.

Thank you. Yeah. Good.

Sorry. And in terms of India, well we still have current production under the existing formula which today equates to around $2.50 MMBtu. We now have the new gas pricing policy that would come up with a price north of $6. I think it's $6.50 the last time I looked. And we're working with our partners to progress what those development options looked like. I think we see good opportunities aligned with what the government of India wants in terms of its desire to bring on its own domestic gas, so I think there are some great opportunities for us. And we still have the issue around arbitration which will resolve itself as that progresses through the legal process going forward.

Okay. So, should we have that on our list for 2017 FIDs?

It is a possible FID that we'll look at for next year. But it will – again, it will have to rank against all the other options that we have.

Sure. Okay. Thanks, Brian.

All right, everybody. Well, thank you very much. I know it's a very busy day for you today. So, we appreciate you dialing in. Brian, would you like to say anything in conclusion?

No. Thanks, Jess. So, well, first of all, appreciate you've quite a busy day today because there's lots of results to try and collate, and hopefully coming out early this morning has helped somewhat with that process. I think it comes back to where we are in the process. We are now well into the rebalancing of the company. We have a big series of new projects coming on stream next year. I think we can now see the balance point sometime into next year. I think we see some firming in prices from where we are now, but nothing sort of majorly north from where we see around $50 to $55 a barrel, and nothing changes within the company in terms of continuing to focus on safe and reliable operations. That's what underpins everything that we do. And thank you very much for taking the time this morning.