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 Second Quarter 2017 Results Webcast and Conference Call. I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley; and 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 Bob.

Thank you, Jess. Good morning, everyone, and thank you for joining us. Today, we are here to report on our results for the second quarter. The environment continues to challenge us, at the same time, it's been another quarter of solid operational delivery in all of our businesses. In the Upstream, we are safely and efficiently executing on our suite of major project start-ups for the year and the Downstream is showing resilient performance, while also bringing on growth. Most notably, it has been another quarter of solid underlying operating cash delivery for the group of $6.9 billion despite the weaker environment. On an organic basis, we were able to balance our sources and uses of cash this quarter. For today, I'll start by looking in more detail at the environment and we'll also look at how the plans we have in place are fit and flexible to respond to the continuing uncertainty. As usual, Brian will take you through the detail of our second quarter numbers and a reminder of our financial frame and guidance. I'll come back to update you on our Upstream and Downstream businesses before we take your questions. So starting with the macro, after a stronger start of the year, Brent oil prices declined in the second quarter. Continuing high inventories and recovering production in the United States and Libya put pressure on prices despite the extension of the OPEC production cuts to the first quarter of 2018 announced in May. Looking over the course of the year, demand for oil is expected to remain robust and increase by an above average 1.5 million barrels per day this year. Supported by continued recovery in GDP growth and supported by sustained lower oil prices. At the same time, non-OPEC supply after declining last year, is expected…

Thanks, Bob. Turning to the environment, Brent crude averaged $50 per barrel in the second quarter compared to $54 per barrel in the first quarter of 2017 and $46 per barrel a year ago. The recent price movements reflect increased production from Libya, Nigeria and the United States, moderated by the extended OPEC production cuts. Henry Hub gas prices averaged $3.20 a million British thermal units in the second quarter compared to $3.30 in the first quarter and $2 a year ago. The global refining marker margin showed seasonal improvements. The second quarter averaged $13.80 per barrel compared to $11.70 per barrel in the first quarter and $13.80 per barrel last year. Turning now to the results for the group, BP's second quarter underlying replacement cost profit was $680 million, around 5% lower than the same period a year ago and 55% lower than the first quarter of 2017. Compared to a year ago, the result reflects higher exploration write-offs and a lower contribution from oil supply and trading, partly offset by higher Upstream liquids and gas realizations and higher Upstream production. Compared to the previous quarter, the result reflects lower Upstream liquids realizations, higher exploration write-offs and a weaker contribution from oil supply and trading. Second quarter underlying operating cash flow which excludes Gulf of Mexico oil spill payments, was $6.9 billion. The second quarter dividend payable in the third quarter of 2017 remains unchanged at $0.10 per ordinary share. In Upstream, the underlying second quarter replacement cost profit before interest and tax of $710 million compares with $30 million a year ago and $1.4 billion in the first quarter of 2017. Compared to the second quarter of 2016, the result reflects higher liquids and gas realizations, the impact of the Abu Dhabi concession renewal and higher production from…

Thanks, Brian. Let me briefly now update you on progress across our two main segments, as it has been a very eventful quarter with more to come as we get into the second half of the year. I'll start with the Upstream and you will have heard us talk before about 2017 as a very significant year for BP. This is proving to be the case. We have already started out three of our seven major projects for the year, two more are imminent. We made a lot of progress in resetting our cost base over the last few years and we expect that trend to continue. This year, we expect unit production cost to be more than 40% lower than in 2013. Around 75% of these cost reductions are from efficiency, so these should be sustainable in the longer term. Beyond this, we're pushing ahead with some really transformational changes as we digitize the business at pace. This stretches from sub-surface modeling to wells construction to plant operations and all the way to electronic procurement. We expect to deliver $13 billion to $14 billion of pre-tax free cash flow in 2021 based on our February assumption of $55 per barrel. This is underpinned by 5% per annum average production growth, continued decline in unit production costs and improved capital efficiency. Looking beyond 2021, we have improved both our capacity for growth as well as the quality of that growth. We believe in the strength of our portfolio which is balanced, increasingly competitive and positioned to reflect changing energy trends. We always look to grow value and returns not just volume and we will deliver this through a continued optimization of our resources through our Area Development Planning process, the recent acquisitions, as well as our modernization and transformation agenda.…

Thank you, and good morning, again everybody. We do have a long list of callers this morning. So in the interest of time and to be fair to those at the back of the queue, we'd like to ask you today to please adhere to our usual convention of two questions only. And of course, IR will be available for follow-up after the call. We will take the first question from Irene Himona of SocGén. Are you there, Irene? Irene Himona - Société Générale SA (UK): Yes. Good morning. Thank you, Jess. Yes. I had two quick questions, please. Firstly, on asset disposals, Brian, you reiterate the $4.5 billion to $5.5 billion by year-end. I wonder if that refers to sales to be announced or actual cash receipts. And have you announced some disposals that have yet to close this year? Secondly, just very quickly on DD&A it's up about 11% in the first half. I wonder if the $8.6 billion is representative of the annualized charge. Thank you.

Hi, Irene. So on disposal, its proceeds, so it'll be cashed in this year. We've already announced over $2 billion if you take into account SECCO. It's probably over $2.5 billion in terms of announced deals. And there's a whole suite of other small, medium-sized transactions that will close in the second half of the year. So the actual range we've laid out there, the $4.5 billion to $5.5 billion is still well-underpinned. On DD&A, I'll have to come back to you on that specific question, but in terms of effectively what we've got coming through so far this year is the new projects coming on-stream, and therefore we start to activate DD&A around those assets. It will pretty much flat line from where we are if we look on a DD&A per barrel basis for this year. It will probably flat line over the next two or three years as we look at the growth projects coming on stream and assets coming off the books as we go through some disposals. But we'll come back to you on the specifics of DD&A and what the track looks like for the rest of the year with IR later. Irene Himona - Société Générale SA (UK): Okay. Thanks so much.

Thanks, Irene and turning next to Christyan Malek of JPMorgan. Go ahead, Christyan.

Thank you, Jessica, and good morning Brian and Bob. Two questions just very quickly, first, you previously mentioned if oil remains low, sort of in the low $40s, that your CapEx can be as low as $14 billion. In light of your cautious view that oil is likely to trade within the range of $45 to $55 next year, your continued efficiency drives and improved cash margins on new projects, do you think there's more scope to reduce group CapEx without necessarily sacrificing sustained (34:56) beyond 2020? And the second question, coming back to oil prices, to Bob, you've outlined an oil price view for next year. Is it fair saying that's your view in the long term too or do you see things reverting higher? Just interested to know how do you think the trend sort of continues through the back end of the decade.

Maybe just on capital frame, what we've laid out is the $15 billion to $17 billion range. I think for next year, I mean Bob will come on to the oil prices, but I think we'll probably see oil prices firming through this quarter as we see demand continuing to grow. That will probably taper off in the back end of this year. So I think a range for next year around $45 to $55 seems like a reasonable assumption today, but a lot could change between now and the end of the year around supply and the demand side of the equation. But in terms of capital, assuming we are around $50 a barrel for next year, then we'd be at the low end of our capital range. And if we saw a prolonged period down to $45 a barrel, we could go below that $15 billion, which is what we've laid out in today's results, and we continue to believe that. We're seeing more capital efficiency come through. You've seen a strong set of cash flows in the first half of the year if you take out – basically it's pretty neutral working capital for the first half of the year if you add the two quarters together. That gives you a pretty good indication of the strength of the cash coming through, and therefore, more flexibility as we go forward. And we'll continue to see capital efficiency and focus on costs and productivity throughout the organization.

And, Christyan, when you look at the supply and demand and the projections out there, I think Brian used the term $45 to $55 for the next year. In our thinking, that's pretty good fairway for us going forward, thinking about $50 oil for the next five years is the numbers we're going to use right now and keep the discipline about it. That'll bring down the cost structures even further in the industry. The U.S. shales are a swing producer. There's always geopolitical events that could create spikes in the other direction. But in terms of our thinking, getting BP to work, getting our breakevens well into the $30s and thinking that it's a rough $50 over the next five years is right now our thinking.

Thank you very much.

Great. We'll move next to Lydia Rainforth of Barclays. Are you there, Lydia?

Thanks, Jess. And, yeah, good morning everyone. Two questions, if I could. Just going back to Brian, on chart on slide 17 around the free cash flow cover of the dividend, if I remember rightly, at the 1Q stage that was shown at $55 real (37:34) and it's now shown at $50 to $55. Is the interpretation of that chart, just so I'm clear, that the business will be breakeven sub-$50 a barrel next year? And then the second one was just in terms of the confidence in the numbers and the projections going forward, when I add up all the projects and things like that, it does look like the numbers are very much risked and there is potential upside within that. Can you just comment on how much confidence – or I was just going to ask, how much risking there is actually in that process? Thank you.

Lydia, so I mean, the second part of the question, we risk all of those projects, and I think, as Bernard laid out, when we laid out the strategy end of February, it implies 5% growth. And of course, those projects are risked across the piece and similarly with the Downstream, as you saw from the Downstream Investor Day. And they're risked for a reason, to sort of say that if you sort of take the middle of the fairway that Bob described and that's what we think the outcomes will be and there's lots of things can move up and down around that range. On the move from $55 real (38:35) to $50 to $55, so well-spotted, and you saw there in the first half of the year we came in cash breakeven. It was actually below $50 a barrel. We still have to offset the scrip going forward, so that's still important for us in terms of next year. And then in terms of where we're targeting cash breakeven next year will be a choice as to where we set the capital. We'll continue to see more come through, I think in the way of costs and capital efficiency that Bob laid out. And as we land our plans for next year at the end of this year, we'll ensure that we set things up to make sure that we are balanced next year, ensuring that we also cover the scrip going forward and make sure that we can offset that on a go-forward basis. But there's a lot of moving parts between now and the end of the year. But you're right to pick up directionally our breakeven prices moving down quicker than we may have anticipated at the start of the year. And first half year is good progress, but there's still an awful lot more to do in the second half.

Perfect. Thank you very much.

Thank you. We will take a question now from Anish Kapadia of TPH. Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP: Good morning. First question is on Macondo. When I look at the balance sheet, you've got a current liability on the balance sheet of about $3 billion. So I just wanted to check, does that mean you'll have around $3 billion of cash out over the next 12 months from Macondo or are there other offsets or further charges to think about? And I suppose just how the kind of PSC settlement works into that? The second question is relating to your U.S. midstream. I know you're limited in terms of what you can say on that, but I just wanted to kind of think about the bigger picture strategy on examining the potential IPO, why are you looking at kind of going down that route rather than an outright asset sale as I believe the majority of your assets are non-operated? Thank you.

Okay, Anish. On the Macondo liabilities, that would be the current liabilities, which would be typically 12 to 18 months out. So you're right to say that that's the right order of gratitude, which we've laid out for you already, which actually can also imply from the ranges we've given you of $4.5 billion to $5.5 billion for this year. We continue to expect to stay in that range and around $2 billion for next year. So I think that all sort of box balances. And we took a small increase in the provision as we start to see the wind down now in terms of final suite of claims in the facility, and we expect the bulk of those claims to be dealt with in terms of determinations through to the end of this year and into next year and the sort of final payments to go out next year by the end of 2018. And then we'll be left with a suite of things on appeal. In terms of midstream MLP, Bob, do you want to just pick up where we are on the MLP?

Yeah, Anish, like you say, we can't say very much about it. But I think fundamentally versus the sale versus an MLP, these are assets that are important to BP to optimize our operations around the U.S., the pipelines, refining. And so by maintaining management interest in it, it's a lot better than just an outright sale, which could damage our optimizations. Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP: Thank you.

Okay. We'll move next to Theepan Jothilingam of Exane.

Yeah. Thanks, Jess. Good morning, gents. Two questions on Upstream hub. Just could you talk about Khazzan and what's on the critical path in terms of commissioning and then ramp up, what's the sort of speed of the production increase we should expect from Oman, please? Second question just on the U.S. Lower 48 gas business. Could you perhaps talk about where you are in terms of cash generation? Are you cash flow neutral on these positions and the progress we're making there in terms of taking out costs? Thank you.

Yeah, Theepan. The Khazzan project is moving along very well. You'll know we've got a 60% working interest in there with the Oman Oil Company. Our latest estimate for start-ups should be by October. Overall progress on the project's up around 99.8%. We've got gas that is filling the plant now, should be about 7 tcf of unconventional gas. We've got another agreement to expand it by 50%, takes it up to another 3.5 tcf. First gas you know we really can't really give the date today. But we've notified the government that we expect it to be in third quarter. Our forecasts for production this year are up around 17,000 barrels a day this year and will be up well over 100,000 barrels a day next year. Plateaued production will be 1 bcf a day gross. So we're feeling very good about the progress of the project and just stay tuned on that.

Theepan, then on Lower 48, for last year we were cash breakeven below $3. And for the first half of this year, we're cash breakeven below $3, so therefore at $3 per MMBTU we'd be generating cash.

Okay, great. Thank you.

Thanks, Theepan. I'm turning next to Alastair Syme of Citi.

Thanks very much, Jess. Brian, you've historically shied away from talking around divisional tax rates. Will we get some disclosure on the Upstream from the (44:10) filings? But can you talk around what the portfolio activity would do to that Upstream tax rate, when we see the full year accounts for this year? And secondly, you know, you've highlighted the WTI-WCS spread in the quarter. Can you give us some, sort of, ballpark sensitivity on how that spread impacts on your Downstream earnings? Thank you.

Yes, on tax, there is a whole suite of inputs that come into that depending on where oil price is, depending whether it's PSA PSC, particularly from a corporate perspective in terms of deferred tax losses that we carry forward. What's happening with foreign exchange rates so therefore it's actually not that easy or straightforward to try and give you an indication of what's happening in terms of overall rate. But I think guidance for the year for the corporation, this year we're probably tracking now above 40%. And remember we moved from around 30%. The range previously was around 25% to 35% with the ADMA concession, we moved the effective rate up to 40% because of the high tax balance that come through with that. On that basis for this year we're now tracking above 40% given the exploration write-offs that didn't attract any tax relief this year. So we're now tracking above 40%. Cash tax rate, Alastair, would typically track around 6% to 10% below that historically so – and actually for the first half it's about 8% below. But other than that I'm afraid I can't give you any much more information. In terms of the WTI-WCS as you'd expect as prices come down that differential narrows in. Also with some of the disruptions up in Canada and producer outages, we've seen that effectively that spread has come in. We've talked historically about wanting something around the mid-teens is where the big Whiting investment came. If the level gets too low you start to run more WTI than heavy. But I think you'll start to see the spread open up a little bit which we've seen recently, but we're not expecting a major recovery as we come through this year and it'll already be driven by pure supply and demand economics coming out of Canada in terms of heavy crude. We don't actually give an indication in terms of what that means on a rule of thumb basis. And so really that's all I can say about the WTI-WCS.

Okay. Thank you.

Thanks, Alastair. Next up Jason Gammel of Jefferies.

I wanted to ask first of all about how you think about leverage relative to the relief of the scrip dividend. Just recognizing that we're now getting pretty close to your 30% ceiling on the end of the quarter and recognizing that divestiture proceeds will pull that down. But is there any level of leverage that you would want to reach before the release of the scrip dividend once you get into a position where you're generating significant free cash flow? And then my second question is a fairly quick one I hope. I've lost my decoder ring right now. I was hoping you could tell me the absolute magnitude that is associated with significantly lower supply and trading contribution.

Jason, thank you. And I'm sure if somebody can do an algorithm with machine learning, you'll probably be able to work out these results from all the various things we've said over the last 10 years. On the first piece, gearing net debt, that's not really – it doesn't cause us any issues in terms of offsetting scrip, so that wouldn't be a determining factor in our decision to offset scrip and we're only talking something cause at, today's levels, offsetting scrip is around $1 billion to $1.5 billion. So it's not a huge amount in the overall scheme of things and certainly the balance sheet could more than absorb that. So the balance sheet will not form a determining step in offsetting scrip, albeit being back into cash surplus on an organic basis will be the biggest driver of that, so that is not a cause for concern. And certainly would not come into the equation even if 30%, there's still quite a lot of flexibility we've got in the balance sheet and 30% isn't a ceiling for that range. It's more about long-term financial framing guidance, so it's always possible to get through. Although I don't anticipate that will happen given the strong cash flows as we've seen in the first half of the year. Supply and trading, overall gas and oil is tracking to plan so far this year. Oil trading had a stronger first quarter than second quarter but actually we add up the first half, it's tracking just at around about plan and is bang on the historical five-year average. So, there's no major issues with 2Q other than the fact it was weaker than 1Q and it was weaker than what was a strong 2Q last year in comparison. So that's the decoding for you. And other than that I can't give you any more specifics.

Thank you, Jason. And we'll go now to Gordon Gray of HSBC.

Thanks. Two quick ones please. Firstly on Deepwater Horizon payments, if I recall the non-fine portion of it, the majority of it is tax deductible. But although you're generating profits at the moment in the U.S., the pre- and post cash tax cash outflows are the same. Can you talk about how much of a tax shield, let's say, is still outstanding from Deepwater Horizon payments and how that may work its way through? And the second one was just one about the R-Series fields in India. Just if you can give us a feel for the clarity you have and if possible some more detail on the pricing of the gas that gives you confidence in the long-term returns from that project? Thanks.

Yes. In terms of the tax credits off of Deepwater Horizon, the majority of those have been booked. A number of them have already cleared their way through the system. And if you think now we're sort of year seven beyond where we were in some of the original provisions that were taken and the only increase, the only credit for the tax charge will be what's been taken for this quarter associated with business economic loss claims that we'd laid out for you in the results. So that continues to work its way through our annual results. And as you say, as we start to see the U.S. come back into profit, you'll see those credits start to work their way through but a number of those credits have already worked their way through the system over the last six, seven years.

And as India has said that they want to increase their share of gas to 20% domestically, we're in with the new contracts market rates that put us well probably – the price will vary a little bit quarter-to-quarter but in the $6 to $7 area for the pricing. With the FIDs that we've put in place and the reengineering and retooling of the cost of the developments coming way down, they've moved way up in our prioritization. We're starting out with the first phase. We've got two more behind it after the R-Series, one is the D55 field which is deep below the KG-D6 platform itself. So these projects are looking very good right now and there's a lot of government support for these things to come on.

That's great. Thanks.

Thanks Gordon. Turning next to Thomas Adolff of Credit Suisse. Thomas Adolff - Credit Suisse Securities (Europe) Ltd.: Good morning. I've got two questions as well and going back to CapEx if you don't mind. Firstly, in terms of capital efficiency and productivity, the levels you have reached today, do you think it is harder to go much further at a steady oil price? And what I'm interested in is further capital efficiency including as well as excluding the benefits from automation, big data et cetera, things like where we are we on the standardization process and in the context of that what is assumed in your 2021 targets? And secondly and perhaps also indirectly linked to the first question, you said your CapEx guidance represents the hard seating in a soft floor. But in the context of the soft floor how low can you go before you start to start the business of capital? And how does it compare at a steady oil price environment again in 2018 versus 2021? In 2021 you have much higher production? Thank you.

So maybe just to start with that Thomas, I think if Bernard were here he'd tell you in terms of longer-term, he's looking to position that division and business to ensure that it's robust at $45 a barrel. And no doubt we may well see those sort of levels again over the next 12 months. So I think there is more capital productivity to come through from all the areas you've just laid down. And I think you'll remember at the end of February, Bernard, talked about all of the modernization and technology advancements that we're making, you'll have seen some announcements in the press around things that we're doing. They will inevitably lead to more capital productivity, which we're seeing right across other sectors. And number of things we've been early adopters of we're now starting to bring it to fruition which you saw some of the things Bernard talked about end of February. So there's more to come in that space. In terms of the short term, because really we're only talking the next 12 months out in terms of flexibility in the frame to the downside, there's probably a billion dollars of capital. So there's downside if we saw a prolonged period of $45 a barrel over the next 18 months. I suspect that will not be the case. But nevertheless we will have plans in place to make sure that we can deal with that and ensure that after effectively giving ourselves three years to get the company back into balance after that four-year period of $100 a barrel then I think it's right that next year we will be back in balance.

And, Thomas, I'll just add on the Upstream, the technologies that are not fully built into our cost estimates will transform new developments will be the transformation we'll see in drilling. Automated drilling will come in, the use of sensors and automation and all across these developments will undoubtedly lead to productivity increases that we haven't yet fully built in. In terms of starving the business for capital, I think it's always going to be the discipline. We have more opportunities than we can actually pursue going forward. So we'll just try to get that balance right and make sure we continue the growth without starving the business of capital, but really driving that efficiency into it. Thomas Adolff - Credit Suisse Securities (Europe) Ltd.: Okay. Thank you.

Thank you. And we'll turn next to Rob West of Redburn. Go ahead Rob. Rob West - Redburn (Europe) Ltd.: Hi, Bob. Hi, Brian. Hi, Jess. Thanks for taking my question. The first one is just a bit of clarification on page 21 where you talk about major projects ahead of schedule, which I think is the title of the slide. I was wondering is that referring to some of the startups this year where the ahead of schedule, Maersk has already been announced in press releases. Or looking down that list, are there any in 2018 or 2019, 2020 that are coming in ahead of the milestones you've set out for them along the way. So that now was the first question? And the second one was just going back to what Anish asked you about the extra provisioning for Macondo. I'd just like to understand a little bit better what is mechanically happening? Where those extra charges need to be taken? I don't know if you can give us more detail on what actually changes quarter-to-quarter, where you have to take those extra charges so we can get a sense of whether any future charges might be sensible for us to kind of put into our numbers as well? Thank you.

Rob, a couple of things in terms of major projects ahead of schedule these are – some of these schedules we've laid out quite some time ago; Thunder Horse South which came on last year was far ahead of schedule and under budget. Of course we've seen West Nile Delta come on this year. Zohr, which was originally a 2018 project now, it'll come on in 2017, of course operating with Eni, Khazzan at one point was a 2018 startup it's now getting close so we've narrowed it back down. If you look ahead to 2018, I'll just pick a couple of projects. I think, Atoll, the first phase in Egypt has potential to be ahead of schedule. It's not inconceivable it could come on before the end of this year, but probably first quarter of next year, that's moved fast very, very quickly. Phase 1 of Shah Deniz, the delivery of gas into Turkey, that's moved up sort of targeting I think probably October next year. And then Maersk is operating Culzean which is we've seen that move up as well. So those are just a few on those lists. And of course, our schedules change all the time, of course as we get further into the engineering we can see it and be more precise. But I think the execution of our major projects team over the last four years has been quite remarkable and a transformation from the phase that we were in before. Rob West - Redburn (Europe) Ltd.: That's very clear. Thanks.

And then in terms of Deepwater Horizon, it's really around the runoff of the final piece of the claims facility. There was a recent ruling in the court which has led to, if you remember, at the very start of this process we had about 149,000 claims in that facility. We're down to 5,000. There's been a recent court ruling which majority-wise underpin the number of other rulings we have which has helped in terms of proceeding going forward. But it's also effectively resulted in the recycle of about 2,000 of the 5,000 remaining claims to go back through the process which is deferring things out, which means admin costs are slightly higher and the re-determination around some of those claims as a result. So hence that's why we've punched through this extra charge. Effectively we were expecting everything to be done by the end of next year. There's a slight 12-month delay to the runoff in the final piece of the claim. But we don't believe it will have a cash impact this year and will have a minimal cash impact next year. Rob West - Redburn (Europe) Ltd.: That's very clear. Thank you.

Thank you. And we'll take a question now from Jon Rigby of UBS.

Thank you. Yeah. Can I ask you about Downstream? I mean you invested a lot of time and effort in presenting to the market on the Downstream about a month ago. With quite a differentiated bit of disclosure and discussion around the separate businesses that go into the Downstream and you talk about some of the progress today, but the disclosures that you're giving are very traditional, one might say somewhat old fashioned. And I think, as you acknowledge, the trading result this quarter emphasizes the volatility in that business. So wouldn't it be better or has some thought been given to expanding disclosures, to talk about some of the progress in the underlying sub-segments around the conversion of sites and other progress that you're making to emphasize progress made in the Downstream with what a quite ambitious earnings and cash flow targets was the first question. The second is, Brian, you talked about the use of cash as and when you moved to cash surplus and you talked about the balance between the anti-dilution of the scrip and CapEx. You didn't mention debt, and I wondered whether over the longer-term, given what's happening in the market, given obviously volatility in oil prices, the impact of shale, et cetera, whether there's been any consideration taken around sort of lowering through cycle net debt as and when you can? Thanks.

So maybe, John, on the second part of the question, our average cost of borrowing is just over 2%. So, I mean, just to put that into context, that it's not that expensive to carry that level of debt. And that you'll recall during the Macondo period of uncertainty, we moved the range down to 10% to 20%. But, no, if anything the push from investors is actually 30% is pretty comfortable, couldn't you go higher? So net debt is not one of the issues that's sort of on the agenda in terms of – now it will naturally decline over time as we go forward and debt rolls off. We'll have choices as to whether we want to renew that debt depending on what the prevailing rates are, but right now, economically, it's actually – it's not a bad place to be in terms of where we are. So that doesn't cause any cause for concern. On Downstream, I think over the last four years, we've done a lot of disclosure. You've got sub-segmentation of the fuels business, we show you lubricants, we show you chemicals, so you've got access to those. I think at the Downstream Investor Day, Tufan laid out a lot of information, which again you'll see in the disclosures, we talk about the number of new sites that we've added so far this year. I think it was something around the order of 90 new sites. We have the Woolworths' transaction, which is in the sort of regulatory phase in terms of approvals going through. And what we're dealing on the convenience partnership side. We also gave you some indication around trading inside the Fuels business, as you alluded to, in terms of volatility. But we'll take on board your comments and we'll talk with Tufan about whether we can give you more disclosures going forward. But you will start to see the underlying improvements come through that we saw over the last two or three years and what we've laid out to 2021. You'll get a lot more information around that going forward.

Thank you.

Thanks, Jon. And the next question will be from Martijn Rats of Morgan Stanley. Martijn P. Rats - Morgan Stanley & Co. International Plc: Yeah. Good morning and thanks for taking my questions. I have two. I also have a question on slide 21, which is the exhibit that shows your major projects over the next couple of years. Altogether, it adds up to 800,000 barrels a day of oil equivalent production. But if you focus on the projects that are oil, as far as I can see, they add up to about 85,000 barrels a day of that total. So a smidgen above 10%, suggesting that the other 90% is gas. Now I know the mix is shifting and that the strategy is sort of moving, but is that really the strategic intent of BP to have the oil gas mix shift so much towards gas over the next couple of years? And the second question is related to the Russia Sanctions Review Act, I have to say I struggle to really understand how much this means, or what it could mean, but perhaps could you give us your view of what it will mean for BP if this was passed in its current form?

Right, thanks, Martijn, both good questions. There is a shift in the portfolio to gas, it's not a 90% shift. We do have the oil projects in there. If you look at the Thunder Horse expansion projects, you've got the Mad Dog project, which is a significant oil project coming down the track. Clair Ridge next year in the UK, Quad 204 this past year, and then with a fair number of these gas projects, there's a lot of liquids and condensate with it. So, I think the number isn't 90%. These projects, we look at as advantaged gas projects. They're not like Lower 48 type projects. They tend to be in markets that are short gas where we have contractual gas pricing so that the economics are clear. The Egypt projects fit into that, the Oman projects fit into that. So there's gas and there's gas, and so these are quite selective gas projects for us. And Mauritania and Senegal will have a significant amount of gas. I'd also add that there's a lot of oil prospectivity there as well, which wouldn't be on the charts. But it is. You've seen our strategic shift. Low cost oil, advantaged oil will still remain a very important part of the portfolio but a shift higher to gas. On the Russia sanctions, we've noticed that there were – the language in the version that went into the House was full of unintended consequences, for example, that might have affected the Shah Deniz project, even some of the Egyptian projects. As I understand it, the language has been rewritten into all that and that now avoids those very, very significant unintended consequences to American companies. The sanctions themselves, as they're written and we'll carefully monitor this, and of course we have to work very carefully within the sanctions, but we're not aware of any material adverse effect on our current income and investment in Russia or elsewhere or our ability to work with Rosneft itself. We stay away from targeted individuals, of course, and don't get involved in any of their personal business. But we've been able to work well within the guidelines for the last three years, and these new ones don't appear to change that. Martijn P. Rats - Morgan Stanley & Co. International Plc: All right. Thank you.

Thanks, Martijn. And we'll go now to Michele Della Vigna of Goldman Sachs.

Thank you for taking my question. I was wondering over the next 12, 24 months, which projects you felt comfortable enough to FID and where you think that more work could still further lower the costs from here. Thank you.

Well, we've deferred a couple of FIDs, you know, in Pike and in Browse, for good reasons. We could see ourselves with an additional FID in Atlantis Phase 3, a very significant oil development in the Gulf of Mexico. The costs are coming down. That's clearly got great prospectivity there. That's one I would think about. We've got another one in the Gulf of Mexico we may consider; we need to work with our partners on that. You might see us with additional FIDs down the road here in India. We've said, we've sanctioned the first one with the R-Series, but there's others in India. And we've just recently sanctioned Angelin in Trinidad. So we'll pace these out. We'll be very selective about them, but we've got some good projects there that you don't see on the list on slide 21, and I'd also add, some of those are oil.

Thank you.

Thank you, Michele. Next question from Iain Reid of Macquarie. Iain Reid - Macquarie Capital (Europe) Ltd.: Yeah. Hi, guys. Thank you very much. A couple of questions, please, one on Senegal and Mauritania. Just wondered how the recent discovery, Yakaar, has changed in any way the planning that you've got for developments there. Is this going to kind of change the focus from the Tortue discovery? And why don't you give us an update on what you're planning at the moment in terms of FID on that project? And second question, Bob, just coming back on this Russia issue, and just perhaps a bit more philosophically, the dividend from Rosneft has now fallen below $200 million per annum. And it looks like it's not going to move very much from that given the outlook for oil prices. I'm just wondering how you feel about the return on the investment from the significant amount of money you've got invested in Rosneft, following the dissolution of TNK-BP. And whether there's strategic upside, which you keep talking about, really compensates for the very low turn you're getting from that investment?

– Yeah, Iain, thanks. On Mauritania and Senegal, we had that significant discovery South of Tortue in Senegal where Tortue is on the line between Mauritania and Senegal. We're drill stem testing a well right now in Tortue. I think this is such a prospective region now. We see resources there. If we look at it, I think there's probably 50 Tcf of gas out there in Mauritania and Senegal. The development concepts, I think will be modular in a way that we'll be able to – we need to appraise this and then we'll optimize it. We have a development concept now for Tortue, but we can alter this depending on discovery of other resources out there. We'll be drilling some wells in Mauritania, (01:09:15) this year. All of those things could change our thinking in terms of what could be a fairly complex resource area and maybe even further in the North and Mauritania there are some oil. But I think what that discovery essentially does it just demonstrates the high potential of the basin itself. So I would stay tuned with that. It's all good news. We'll see what happens on the DST in these other wells that we're planning to drill this year. On the Rosneft dividend, by the way, there'll be an Extraordinary General Meeting of Rosneft in September where they'll begin to declare dividends twice a year. So it's always been one-year dividend once a year. We'll see another dividend payment in the fourth quarter. I'm reasonably sure that's the outcome from the voting. Rosneft is 5 million, 5.5 million barrel a day company. It has lots that's doing to make itself more efficient. Russian government is reviewing their tax system because it was basically put in place at $100 oil. I still believe it has lots of upside potential. It, like BP, is working to get its breakeven cost down. And so I think it's doing exactly that strategically the things any company should be doing at these oil prices and I still remain hopeful that we'll see improved profitability from them. But I think the step of going to a dividend twice a year based on half-year earnings and then looking at the portfolio, the tail of the portfolio is all positive. Iain Reid - Macquarie Capital (Europe) Ltd.: Okay. Can I just ask any update on the timing of FID for Tortue?

Well, no, not with the DST going on now. I think that's part of it is just to appraise it further. But we've done a lot of engineering work with Kosmos, and we'll be able to move pretty fast on it. But no, I can't give you a date right now. Iain Reid - Macquarie Capital (Europe) Ltd.: Okay. Thanks, Bob.

Thank you. And we'll take a question now from Chris Kuplent of Bank of America.

Thank you. My two questions are as follows. Firstly, Brian, you once again referred to the $2 billion to $3 billion annual disposal rate that we should expect from 2018 onwards. Is that a net number, or should we assume that that proceed generated will partly cover ongoing oil spill payment costs and at the same time be reinvested in external growth, the likes of Zohr and Mauritania that we've seen over the last two quarters? And my second question would purely be for a clarification. You said you have announced $2.5 billion of disposals so far this year. Can you already tell us how much cash flow those assets have generated in the first half so far? Thank you.

So on the second question, Chris, the difference, it's $800 million of proceeds have come in in the first two quarters and the difference is of course SECCO, which is due to close by the end of this year will be the delta between those two pieces. And then on the $2 billion to $3 billion, that – I mean, it's not that they will cover in any one year. But so effectively over time, what we said disposal proceeds will cover Deepwater Horizon payments and inorganics. And for next year, actually that will be the case. So something around $2 billion to $3 billion will cover $2 billion of Deepwater Horizon payments that's currently forecast for next year. If we look at the schedule of payments to come out and where we think the claims facility is and the balance of inorganics in terms of cash payments in 2018, so that's correct.

I'm sorry, Brian, for SECCO in the first half in terms of cash flow that you've still consolidated in terms of run rate?

In terms of proceeds or in terms of the earnings in the assets?

Underlying earnings.

No. So the cash that is consolidated inside the numbers in the first half of the year, and that will only be deconsolidated when this transaction closes, once it goes through regulatory approvals in China.

And in the first half that would have been a few couple of hundred?

We don't do cash numbers by sub assets (01:13:33) you'd expect, Chris, but there is a significant amount of proceeds to come with the closing of that transaction in the second half of the year, roundabout $1.7 billion is the full consideration.

Yeah. Okay. Thank you.

Thank you, Chris. And we'll take the last question now from Biraj Borkhataria of RBC.

Hi. Thanks for taking my question. I had a couple. So, firstly in the Lower 48, the data you've provided shows that the costs of – or the operating costs have gone up for the last couple of quarters. I was wondering if you could talk a little bit about the underlying trends you're seeing there. And then secondly back on FIDs. I just want to get a sense of how you're thinking about this going forward. One of your peers has talked about 2017 being a window to lock in bottom of the cycle service costs. You don't seem to be in as much of a rush. So I was wondering if you could talk a bit about what you're seeing maybe in the offshore market or any commentary there. Thank you.

On Lower 48, it's nothing more than phasing of where we are in some of the various programs. We obviously have a choice in terms of what we're doing in the drilling space each quarter. So it's quarterly noise that you can see coming through those numbers. But the long-term focus continues to remain on making sure that we continue to drive efficiencies and costs through into that business and what we're learning from the various activities that we've done that we laid out for you last year.

And Biraj on the FIDs, you're right. Well, some of the competitors are saying 2017's the year to lock it in. We have been locking in in some of the low yards spaces and contracts for the FIDs we've done in 2016 and 2017. Not convinced that this is the low point, particularly in the offshore and offshore drilling, for example, where I think there's such a big oversupply that you can expect to see drilling costs come down. So it's not clear yet that we have to rush to lock these in.

That's very helpful. Thank you.

Thank you, Biraj.

And I think that's the last of our questions. So thank you very much everybody for helping us run a more efficient call today. And I'll just hand back to Bob for closing remarks. Thank you.

Thank you, Jess and thank you everyone for listening today. It is quite a bit shorter, you may not feel like it but it's been quite a bit shorter this quarter than the other quarters, which is absolutely based on your feedback. I'll just say in February we laid out a strategy for where we're heading, getting our business, readjusted for the new price environment and we need to build a track record. This is only the second quarter out of the 20 quarters that we've laid out then. So we'll just keep coming back snapshots as we move forward on this. I think we've delivered pretty well in this quarter and particularly as you know, we really drive our business for cash and that's the most important number that I think comes through on this quarter. So thank you all very much. See you next time.