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 2015 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 to factors we note on this slide and in our U.K. 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.

Thanks, Jess, and hello, everyone. Thanks for joining us. It has been a very important quarter for BP. We reached agreements in principle in the United States to resolve the largest remaining liabilities in relation to the Deepwater Horizon oil spill. This has been recognized as a landmark step forward by all parties, and leaves us all able to chart a much clearer course for the future. The second quarter environment has also continued to test us. As you've seen, our Upstream earnings for the second quarter remained under pressure, reflecting continued oil price weakness and the large maintenance program we have underway this summer. The result also includes some large non-cash write-offs. At the same time, there is clear evidence of the underlying strength and resilience of our businesses. Our Downstream continues to perform strongly, and there are clear signs of efficiencies – sustainable efficiencies and cost reductions – right across the group. Underlying cash flow for the quarter also improved. So I will start with an overview, including our thoughts on the future. In a moment, Brian will go through the results in detail. Then I want to come back and give you an update on our interests in Russia, and take a brief look at progress in our businesses. After summarizing, there'll be time for Q&A. I'd like to start with a reminder of the near-term priorities we laid out in February. As you know, we have held the view for some time that oil prices will be lower for longer, but whatever the oil price charts look like, we are clear on what we need to do. To describe this simply, we focus on the four D's of delivery, divestments, discipline and the dividend. On delivery, we've had a strong first half of the year. Group…

Thanks, Bob. And hello, everyone. Starting with the environment. Brent oil averaged $62 per barrel in the second quarter, up from $54 per barrel in the first quarter, but still significantly below the average of $110 per barrel in the same period last year. Oil prices have fallen back again over the last few weeks in response to persistent weakness in market fundamentals. Although demand has been stronger, OPEC production is running higher than the 2014 average and production in the United States has remained resilient. The recent agreement to lift certain Iranian sanctions has also raised the prospect of additional production coming onto the market. Henry Hub gas prices averaged $2.65 per million British thermal units in the second quarter, over 40% lower than the same period in 2014 and slightly lower than the first quarter average. Continued strong growth in gas production has left the market oversupplied, pushing gas prices down to levels that compete with coal for power generation. Our global refining market margin averaged $19.40 per barrel in the second quarter, the highest level since the third quarter of 2012. Margins are being supported by strong gasoline demand, tight supplies on the U.S. West Coast and low product stocks outside of the United States. At the same time, U.S./Canadian crude differentials were at their narrowest since the second quarter of 2009. We expect oil prices to remain soft over the short to medium-term while we expect refining margins to respond to changes in regional supply and demand as we see out the summer driving season in the United States. So, turning to the results. BP's second quarter underlying replacement cost profit was $1.3 billion, down 64% on the same period a year ago and 49% lower than the first quarter of 2015. Compared to a year…

Thanks, Brian. First to recent developments in Russia. In June, Rosneft held their annual general meeting in St. Petersburg. Amongst other matters, shareholders approved the once a year dividend payable for 2014 as Brian mentioned, and voted for the new Rosneft board. In addition, to my own re-election, we now a second BP Executive on the nine-person board, Guillermo Quintero. Guillermo is currently BP's Regional President in Brazil and is a highly experienced oil and gas executive. Beyond our shareholding in Rosneft, we recently signed agreements to purchase a 20% equity share in Rosneft's Taas project. This project is an existing conventional oilfield in Eastern Siberia which currently produces around 20,000 barrels of oil per day. The full field development plan for Taas ramps up production to 100,000 barrels a day by the end of the decade, with further potential for gas production. Along with the Taas equity, we also agreed three conventional exploration areas of mutual interest with Rosneft: one in Eastern Siberia located around the Taas interest in a relatively unexplored region; and two, in the already prolific Western Siberian hydro-carbon basin. We are pleased with the progress both through our shareholding and also in partnership with Rosneft. As always, we remain mindful of the geopolitical situation but look forward to continuing to pursue these and other potential future opportunities where not prohibited by sanctions. Turning to the Upstream and starting with exploration, we made a high-value discovery with the Atoll well, offshore Egypt, in the first quarter. In the second quarter, we've had a further gas discovery at the Nooros prospect in the Abu Madi West lease. We expect production from this well later this year and we see follow-on opportunities in neighboring BP operator blocks. In projects, we successfully started up Greater Plutonio Phase III in…

Thank you for waiting on the line, everybody. We will take the first question today from Jason Gammel of Jefferies. Are you there, Jason?

Yes I am, Jess. Thanks very much and thank you for the presentation. My question is around the cost efficiencies that have been gained, the $1.7 billion year-to-date. You made reference to having to absorb the rig cancellations within that. I would assume that this is a process that was ramping up from beginning of the year. So can you give us any color, Bob and Brian, around how sustainable this is in the back half of the year? Are there further gains to be made?

Jason, hi. Thank you. Well, there are further gains. We're sort of well into restructuring of costs in the Upstream and will continue on later this year – most certainly it'll be in some of our big centers around the world, Houston, some more in Aberdeen. You are right, the rig cancellation costs, had we not done that and used it as capital, we would've even seen a higher cost reduction.

Yeah, and actually also, to point out that we're taking a higher restructuring charge as well this quarter, just to flag that in December we'd said that we'd set aside $1 billion for restructuring. It looks now more like $1.5 billion for this year. You can recall, this program started on the corporate side post the big disposal program. Roundabout 2.5 years ago, we started talking to you about the restructuring of our corporate overheads. That's really what led us down the path of the $1 billion restructuring. We're now into the deflationary period in terms of deflation coming through now and the results in the cash costs, so I think you'll see more as the year progresses. And the additional restructuring charge we've taken this quarter, I think is a signal that there's more cost to come out the system.

So can I just take it from that, that the controllable costs could be down by more than $3.4 billion on an annual basis?

No. I would never – I think I've always said on these calls – never go for multiples of what you see in the first half of the year. There's lots of moving parts in the numbers. The general trajectory though is still down.

Okay. Great. Thanks.

Thanks, Jason. Over in the U.S., Blake Fernandez of Howard Weil.

Hi. Thanks, Jess. Brian, I wanted to clarify, you made some comments on the gearing band of 10% to 20% and obviously, you're at 18.8% at the end of the quarter. With more clarity on the legal front, I just want to make sure, were you kind of insinuating that that band could retrench higher back to the 20% to 30% level that we've seen in the past?

Yeah, thanks, Blake. I think it's really just putting it in the context of where we are. We moved to the 10% to 20% band post-2010 as we refinanced the balance sheet. And I think it was just right with the degree of uncertainties, both in terms of Macondo litigation but also the general environment that we moved into that band. I think the only point I'm making is that where we now sit in that band is a much stronger context now that we know the scale and scope of the liabilities, pretty much the majority of liabilities associated with Macondo going forward. And the way in which that deal has been negotiated over 18 years creates the space to say actually within the current context that's a much stronger place to be. In terms of where we sit into the future, there are so many moving parts. We're not signaling at this point that we're moving out of that 10% to 20% band, but it's a far more comfortable place to be knowing what the liabilities are going forward.

Okay. Thanks. If I could just ask one follow-up too, maybe of Bob. Bob you've had a thesis of lower for longer on oil, which has proved correct so far. You've also come out recently in support of a carbon pricing system and in looking at the project sanctions, the only project you've really moved forward on is a natural gas project. I'm just curious if you can elaborate a little bit if we could potentially have a strategic shift underway here in preference of gas over oil? Thanks.

Yeah, Blake, we have just moved past the 50% – we're roughly right now at 50% of our portfolio in terms of production is now gas versus oil. Part of that is because we had oil projects coming on and in the last two years we have sanctioned significant large gas projects. So, down the road, by the end of the decade, we'll be between 55% and 60% gas when the Oman projects and the Shah Deniz projects come on. Strategic shift? I mean it's clear that carbon pricing and carbon emissions are going to be a focus of the world. We think having that reduced carbon footprint is going to be a good thing, but we're certainly not abandoning the oil and gas industry – or the oil industry. Carbon pricing, we have a view on carbon pricing in the sense that the world is coming together in December. We think that the world really does need a framework to work within. Number one, should be energy efficiency because that is the biggest single lever in terms of reduced emissions; and after that, a carbon pricing that can be used by the world where the proceeds from that don't just go into the general funds of the world, but actually move to solving the transition to lower carbon energy over many decades. And we've taken a position on that with now 11 other companies in an oil and gas climate initiative. It's going to be part of the focus. Strategic shift? I think so. I think it's a natural one with our portfolio and the projects we see ahead.

I appreciate the color. Thank you.

Thanks, Blake.

Next question from Jon Rigby at UBS.

Yes, thanks. Two questions actually. The first, just a point of clarification on these cash cost reductions. Is the $1.7 billion, the savings that you've made over the first half of the year, are where you're running ratably at the end of the second quarter, just so I can get a handle on that? And then secondly, just picking up on the high expiration charge that you've taken this time around which a large portion is write-offs. So I understand it's not cash, but I can see from your accounts that your intangible drilling costs – the stuff that you've got on the balance sheet – have been rising very significantly over the last three years or four years. Is the process of looking at your portfolio, rescheduling when you go ahead with projects, deciding whether those products are appropriate or not, going to have implications for what you're carrying on the balance sheet and, therefore, should we be expecting larger non-cash costs over the balance of this year and maybe into 2016 running through the expiration charge? Thanks.

So, Jon, on the first question, it's a straight simple delta. It's just not run rate, it's the absolute quantum is $1.7 billion lower first half versus first half. On the intangibles, you're right. I think the last time I looked, it's tracking just below $20 billion in terms of expiration intangibles, and we'll continue to simply to process each of those prospects. It's increased over the last four years or five years given the amount of ramp-up we've had in the expiration activity, so it's not surprising. The typical expiration write-offs have been running at an average over the last four years or five years around $400 million a quarter. You've seen more this quarter and even last year, but I don't think it's an indication of a trend that you should expect more and that continues to ramp-up going forward. It's just a reflection as we look at specific projects. And Libya was a bit of a one-off this quarter given where we got to in the process and what was happening in the country itself. So I wouldn't take that as a leading indicator for future.

Or for the filtering process ongoing?

Yeah. I mean, we're going through all the prospects right now. It's a good place to be in terms of prospects that we have going forward, and some of those we'll choose to progress and some we won't.

Right, okay. Thank you.

Moving on to Irene Himona of Société Générale. Go ahead, Irene. Irene Himona - Société Générale SA (Broker): Thank you, Jess. Good afternoon. I have just two questions please. Firstly, on lubes. In Q2, obviously profit rose very substantially. I think we were up 26% year-on-year. And for a long time the average quarterly run rate was around about $300 million, $320 million. In Q2, we were close to $400 million. Given that you don't disclose anything other than profit, is there some guidance you can give us on whether the Q2 lubes profit is sustainable going forwards? And then my second question concerns dividend payout. Earlier, you reset costs and CapEx. Do you look at the payout ratio at all? Is it part of your financial framework? Thank you.

Thanks, Irene. I'll take the lubes and then Brian on the dividend. I think we are seeing some things that are – we don't give out the details of lubricants – but a strong factor is the growth of some of our power brand sales and some of our lube brands like Edge and Magnatec and GTX, especially in the Americas and China. So, I think we are seeing sustainable sales increases and volume increases in those markets which are growing.

And then on the question around payout ratio is absolutely, Irene, of course we look at those. It's important that we make sure that we can underpin the balancing of sources and uses of cash. And I think as Bob laid out in his comments, we could see the oil price getting soft at the middle part of last year. so we'd already laid in plans for this year at lower prices. Obviously, we saw the big drop off in the fourth quarter and we've adjusted things accordingly through this year. And it will take a couple of years as we get things back into balance in terms of sources and uses of cash. But yes, we do look at payout ratios. Irene Himona - Société Générale SA (Broker): Thank you.

Thanks Irene. Back in the U.S., Guy Baber of Simmons & Co. Guy Allen Baber - Simmons & Company International: Thanks for taking my question. Bob, I believe you mentioned that growth through the cycle was still a key objective for the company. So I was hoping you could just elaborate on that comment, particularly in light of the rephasing of projects and the significant reduction to capital spending you all are achieving relative to the view just 12 months ago. So the question is at sub-$20 billion of CapEx annually, do you believe that that is enough capital to organically grow the business longer-term and replenish the portfolio? Or would that level of CapEx need to be supplemented by some amount of inorganic activity? Just hoping for some more thoughts there and then I have a more specific follow-up as well.

Yes, Guy. We do think that we can see underlying production growth with the projects we have and these levels of capital out through the end of the decade. I think we can see with deflation, we can continue to develop these projects and move them forward and we'll just get more activity out of less CapEx going forward. So I think we can. And the deflation, to give you some extent of the deflation across the various geographies and sectors, the rig rates have come down very quickly with drops of about 30% some places, and more already seen in some places. You've got the real impact of oversupplied market there. Our development costs for new projects, we're projecting to deflate by as much as 20% to 30% depending on the project. So we think there is absolutely scope here for having growth through the cycle with lower capital. Guy Allen Baber - Simmons & Company International: Okay. Very helpful. And then I wanted to discuss also just the U.S. Lower 48 business a bit more. But you have a half year under your belt now of that business operating as a separate entity. The macro environment has also changed tremendously from the time when you announced the separation there. So I was just hoping at this juncture you could give us an update as to how that business has performed relative to expectations, the extent to which perhaps you've been able to improve the cost structure, and how that performance in that business is influencing strategy and your thoughts around capital allocation as you move into next year. And also, how do you assess at this point the size of your position in the Lower 48 relative to what you would view as strategically optimal?

Okay, Guy. That sound like a half hour answer to the question. It's a good one though. So there's no question we feel like we've improved the competitiveness of the business. We've done all kinds of structural things, organized it into five sort of accountability-based business units that can move very quickly in implementing capital changes and cost reductions. So far, the kinds of things we're doing is we're managing the producing wells better, new artificial lift, we're reducing some of our costs to drill wells. We've actually increased the number of rigs running from around two up to ten now across the business units. At the end of 2014, we only had two in fact. We've got seven in the midcontinent area, two rigs in East Texas and one rig in Wyoming. So, we've also seen an increase from the drilling and the activity in the percentage of liquids, which is up pushing 20%, about 18% now. So our production across the lower 48 is about 280,000 barrels per day equivalent. So we're pleased with it. Obviously, it's challenged with the lower prices right now, costs coming down. The team, the executive team, has come into that business. We have reduced the size of it in terms of the number of people. I think it's much more efficient and it's moved out of our Houston campus into lower overhead activity. So I think we continue with the desire for it to be a market visible high return onshore operator in the U.S. It's got about 1,200 employees today across five states and we think this – I wouldn't call it an experiment – I think it's a real restructuring activity we've taken on to be competitive. We knew we weren't and they're doing a great job. So, it gives you some sense of it, Guy, without too much. Cost structures are coming down. Guy Allen Baber - Simmons & Company International: Thank you.

Okay, Guy.

Thanks, Guy. Back in the U.K., Theepan Jothilingam of Nomura. Go ahead, Theepan.

Yeah, hi. Good afternoon. Thanks, Jess. Just a few questions actually please. Firstly, just coming back to the PSC settlement, I just wanted to understand how you thought the admin charges would progress through this year. I mean is it right to think that now with the BL (50:45) claims and that deadline passed, that that charge starts to drop away? Secondly, just coming back to the oil projects and FID, you talked about the reengineering on Mad Dog. Is that still a 2015 event in terms of sanctioning? And what type of price do you test down to? What's your low case now in terms of oil prices for sanctioning? And then thirdly, Bob, I guess a concern for investors has been that you discuss selective acquisitions. So can you just sort of elaborate on what you think is the right type of strategic deal for BP, scale, type and if you are in the lower for longer camp, is it right for BP to do a deal sort of in the next six, twelve months?

So maybe, I'll just pick up that first question on the PSC settlement where we've taken additional administration charges this quarter, Theepan. We've now provisioned out to the end of 2018. If you look at the total number of claims still yet to process, there's still just about over 50% of the total claims still yet to be processed. We saw a big, big uptick in the last ten days before the June 8 deadline. It's not clear what the quality of those claims will look like as the administrator works his way through that, but we are working with the administrator in terms of the administration for costs of the PSC settlement and of course, we do expect that to taper down by the end of 2018. But we've now fully provided what we believe to be the right level of administration costs going forward, and now it's simply matter of what the business economic loss claims look like. And it'll probably be another couple of quarters before we actually have sufficient actuarial data to make assessments on them in terms of forward provision, but we'll continue to review that each quarter.

And on, Theepan, Mad Dog as you know, is the second phase of the Mad Dog field in the Gulf of Mexico, is a very perspective project that we've been working. Now with the settlement, I think it's clear about our investment plans in the United States. We're working with our partners there. As we've retooled and reengineered that project, the costs have come down substantially. We'd said at one time we may FID it before the end of the year. I think where we are now, it could be towards the end of the year; it could be early next year. What we're finding is we see the deflation costs coming down. What we have to decide is at what point do we say they're going to continue to come down. We're just going to try to optimize the economic point of the FID, but it's still very much on the cards. And in terms of acquisitions, it's never a good idea to talk about acquisitions or scale of acquisitions. I think what we will continually do is scan and screen for deepening and existing projects as a starter. I think that simplifies our activities without any overhead. That's an obvious one. And I think commenting on acquisitions, I think probably the bigger point for us is thinking about value over volume, and so we're going to pursue the value, and I think we'll just see. I think the landscape is quite uncertain in the industry and it will be for some time, and that will throw up all kinds of challenges and opportunities for companies that are well positioned for it. That's probably all I should say, Theepan.

Okay, fair enough. And just – I mean, can you give any sort of parameters on what you're testing down to, to get in terms of project economics?

Yeah, we – yeah, sorry, I forgot. Q – [06NK42-E Theepan Jothilingam]>: Sorry.

We are testing our projects, believe it or not. We're certainly testing them right now and looking at decisions around the $60 mark. We're of course, running and looking at it at $80. We even do a little stress test down at $40, but we think that they probably don't accurately reflect the cost structure today. So right now, we're looking at these around the $60 mark.

Thanks, Bob. Very helpful.

We'll take the next question from Oswald Clint of Bernstein.

Thank you very much, Jess. Yeah, Bob I had a question really on Russia and this kind of strategic move into East Siberia. I guess it wasn't, it's not a big part of Rosneft or I guess TNK previously. So what's changed to kind of make you move over to that region where, of course, the geology is a little bit different? Or can you talk about maybe how big you think this becomes? Could it become a new hub? And does it really fit into that category you were mentioning about near-field exploration kind of pulling volumes through much faster? And then maybe secondly, maybe a question for Brian. In terms of the Lower 48 again, in terms of your separate disclosure, I think you're saying $8 or $9 a barrel production costs, which I guess when I compare that to forty or fifty other E&P's, looks pretty good already – at least versus the average, $2 or $3 less. So I guess the question is have you really pushed – it looks like you've done quite a bit already – or is there a kind of significant further movement on the number? Thank you.

Oswald, I'll take Russia and then Brian. Actually, Oswald, if you look at East Siberian oil basins around in that area, there is significant activity by Rosneft out in that area. TNK-BP had a very large field out there called Verkhnechonsk field and now it's of course, part of Rosneft. And it is an area where the East Siberian pipeline goes through. So, there's quite a bit of discovered fields out there, and an additional exploration AMI seems very appropriate given the basin geology. And of course, the Heartland, a very, very large Western Siberia basin which is sort of where everybody's big production in Russia, is of all the companies. We have signed two areas of mutual interest there which is about 265,000 square kilometers. Two very large areas there, and we are conventional oil exploration out there as well. So we see both of those as key to the activities of Rosneft and for BP, not wanting to just be a financial investor in Rosneft, to partner with them.

Oswald, then in terms of Lower 48, you are right to highlight it from the disclosures. It's down 6% in terms of production costs and we would continue to expect that trend to decline with the new team that we've got in place, the new approach that we have to Lower 48. So I think there is more to follow on this and you'll see that as the next four or five quarters progresses. But we are now running that business in a very, very different way than the way we were before.

Okay, very good. Thank you.

Right. Doug Terreson at Evercore. Are you there, Doug?

I am. Good afternoon, everybody. I have a couple questions. First, because right sizing of the cost base is obviously becoming a pretty important objective, especially based on Bob's challenging comments today. I just want to see if there were any metrics or different markers that you guys have related to the different divisions that could provide a little bit more specificity meaning, we talked about Group cash costs earlier, but is there any color that could be provided on the different divisions to just give us some insight going forward?

Yeah, Doug it's Brian. Maybe just sort of – probably our biggest indicators which is one of the sort of tough areas for us is around head count. As I said earlier, we started this in the corporate restructuring space where we're seeing significant head count reductions both in terms of our own employees, but also contractors where we tend to run up bigger contractor work force in places like IT&S. But then, if you look at the two divisions, you are also seeing significant head count reductions both in Upstream and Downstream as we progress through the year. And I think you'll see more of that before we get to the end of the year, hence the larger restructuring charge. Then if you look at various metrics in terms of benchmarking we are also seeing improvements, Lower 48 was one example. But across the piece, we're are looking in terms of how we drive deflation through the system.

Okay. And I had one more questions – one more question rather. An important thing for the company over the past several years has been value over volume and I think it's served you guys well. And I think Bob mentioned a few minutes ago that, that would remain the relevant thing for strategic activity as well, that is, if they were to materialize. So, when you guys think about this phrase value over volume, what specific criteria are you referring to, meaning what's most important for the company when it thinks about capital allocation today, and also strategic activity if it materializes?

Yeah, good point, and Doug, and hello. It doesn't mean that volume growth isn't something that we will strive to do. We actually believe that we can see the potential for production growth between now and the end of the decade out there. But, what it really means is that we're going to strive for every additional marginal barrel of production that will have a higher margin than our existing portfolio, so that we bring up the margin of the entire portfolio with the decisions that we make. We have, by necessity, had to divest $45 billion of our assets, but actually what that has done has allowed us to focus the portfolio and increase the average margin of the portfolio in the 15 major projects that were brought on from 2011 through 2014 had twice the margin of the existing portfolio. So I think that's how we'll think about decisions that we have to make. Of course, there's a cycle in the oil prices, you have to make a call on how you evaluate them. And then in terms of strategic steps, or other things are deepening in projects, I think that's a good for all seasons philosophy. I think we got on the treadmill of driving production rather than keeping our eye on the margins. Now, we are a believer that there is value – and I think the world has played itself out since 2010, 2011 – that vertically integrated companies have a role here. So we're seeing the group benefiting from strong Downstream margins, a very focused Downstream portfolio as well that moves through the cycles. So we think that not only is that counter-cyclical benefit, but we really do see the linkage between our Upstream and our Downstream, and what I think is a very skilled trading organization as well.

Great. Thanks for the elaboration, Bob.

Okay, Doug.

Next, we'll take a question from Thomas Adolff of Credit Suisse. Go ahead, Thomas. Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.: Thanks, Jess. Two questions, please. One on decline rate and one on your 4D's, divestments. But firstly on the portfolio decline rate, back in December at one of your breakout sessions at the Upstream Day, you said that the portfolio decline rate is around 4% to 5%. Presumably that was based on the higher spend on brownfields, and obviously you never gave an exact split of how – where the CapEx was cut. So I wonder whether that 4% to 5% is still the case, or whether that's still too early to say are the effects of the lower spend? Or are you just successful in maintaining that range as you say you're getting more from existing assets from a lower spend? Secondly, one of your 4D's, divestments. And feel free to correct me if I'm misquoting you, I believe beyond 2015 you used to say the disposal plan should be around $3 billion per annum. A normal portfolio optimization approach, which obviously would also then come with acquisition on this – organically, you're successful in adding resources. But if you look at this $3 billion per annum figure in this environment in the context of a leaner portfolio since Macondo, is that something you're still confident you can achieve?

Thomas, maybe I'll just take that last question. In terms of $3 billion, I think the number we used before is $2 billion to $3 billion of natural churn which is what we've done historically, and see no reason why we wouldn't do that on a point forward basis, so it would still give you indications of around $2 billion to $3 billion in a portfolio of our size. I think all you're seeing is, it's a different mix of assets now than those late life assets that were high returning, highly depreciated assets that you saw in the $45 billion program. We are now seeing some early life assets that actually aren't in production – things like the Paleogene we did at the start of this year. So it will be a different mix going forward, but we'll continue to look to churn $2 billion to $3 billion of the portfolio each year.

And Thomas, on the decline rate, I think I'm going to take your point which is a good one all the way back to reminding the obvious, that safety is good business and all the turnarounds that we did in the company from 2010 up through 2014 which was an enormous program has led to some of the best operating efficiency we've had in the company. The months of May and June were 95% operating efficiency of our Upstream assets, and the North Sea in particular, has come up in its efficiency as – and the Gulf of Mexico has been working well – although we have the turnarounds, the normal turnarounds, down. What that has done is allowed us – and I just went through this – the base management, base production management, those decline rates now look actually a little better in the sense that we're sort of seeing 3% to 5%. We said 4% to 5% in December. We're actually seeing around 3% to 5% possibly as well. So all of that leads to the good operating cash flow. It's sort of a virtuous circle of safety, reliability, uptime and efficiency, more operating cash flow and then maintaining the base. Thomas Y. Adolff - Credit Suisse Securities (Europe) Ltd.: Perfect. Thank you very much.

Next question from Rob West at Redburn. Rob West - Redburn (Europe) Ltd.: Thanks, Jess. Hi, Bob. Hi, Brian. I've got a question on some of your greenfield projects, three in particular. I guess as a factor at the moment of things that were designed and contracted and locked in in, say, 2012 and 2013 and can't really flex that much because of the development plan or the contracts. And things like Mad Dog Phase II, where it looks like even since December, further costs have come out from renegotiating contracts and redesigning the work. How should we think about big greenfields because (1:06:00) and the West Nile Delta in that context? Are they – since they're effectively sanctioned in the last year and they're in the category of things that can move in terms of cost, can move in terms of design? Or should we think about those as the budget's just totally locked as what was announced? And then my second question is on gasoline, where the cracks have been strengthening relative to diesel. I think you're one of the more gasoline heavy of the majors. Is there any change in the configuration of your refineries? Can you get more yield out on the gasoline side and have you taken any steps to do that already or do you see the margins just normalizing in the second half of the year? Thanks very much.

Yeah. Okay, Rob. A couple of things. Well, one thing we've learned over time is what we don't want to do is in the middle of a project change the scope. So when you look at projects that are essentially pretty early here, West Nile Delta, we reengineered that for several years and we are in fact, we FID'd that in the first quarter. It's a big project, five Tcf of gas. We think it'll be onstream 2017, 2018. We are – and it'll use existing transportation process infrastructure there – we are seeing deflation come through. We just went out and spudded the first well on the development side of it and the rig rates are very attractive. So I do expect to see that coming through in projects like West Nile Delta. Shah Deniz, we sanctioned that project at the very end of 2013 so it was during 2014. We have seen deflation come through on a variety of things from even the steel in the pipelines to – it's a little bit harder for drilling in the Caspian because it's sort of a landlocked sea to an extent – but right now, that project is under budget and ahead of schedule, which is good. And then Oman, which is a nearly 300 wells over 15 years, we're certainly seeing the deflation coming through in the cost of the wells and in the processing plant there. So the ones that we have in train, those big three that you talked about, to varying degrees, West Nile Delta we'll see a lot, Shah Deniz a reasonable amount, and because it's onshore in Oman and not offshore in the yard somewhere, it's definitely going to see cost deflation as well.

And then in terms of refining and our ability to switch yields, there is some degree of yield switch we can sort of flick between 4% to 5%. I'm not sure we're that much more gasoline-heavy than the rest of the industry. We have got a much smaller footprint in terms of a refining portfolio; we've got out of somewhere close to 13 or 14 refineries over the last 13 or 14 years. We're now down to a portfolio of assets. We've got some inside that portfolio like Cherry Point, which is heavily linked towards diesel, jet fuel. But in terms of the ability to move some of the yield it's sort of margin. I would also say that these Q2 refining margins that we've seen have been very strong, supported by strong gasoline demand and tight product supplies on the West Coast. But actually, we see some of those correcting as we go through 3Q and 4Q. Rob West - Redburn (Europe) Ltd.: That's very useful. Thanks. Thank you.

Okay. We'll take a question now from Chris Kuplent of Bank of America.

Thank you, and good afternoon. First question is on CapEx. I just wanted to understand a little bit more about your comments, Bob, where the savings have come from. You've got a range there, I guess, somewhere between 10% and 20% on average. Can you translate that maybe to your current CapEx budget which you set out at $20 billion for this year? Now you're seeing it already lower. How much of that CapEx budget as you look forward into 2016, 2017 has now been, you would say, satisfactorily renegotiated and is committed. That would be helpful to get an idea around remaining flexibility as we look out. And I guess the second question is simply a boring question, sorry, Brian, just wanted to come back and ask you halfway through the year whether you can comment on your full year guidance on things like production which was meant to be flat year-on-year, D&A all those other lovely items that you have in your full year results presentation. Thank you.

Okay, I'll take the more colorful one, CapEx deflation. Thanks, Chris. Well, we don't think we've seen by any means the deflation that's yet to occur, I mean, as the world moves into what I think does look lower for a period of time here. Typically, if you go back in some of the other cycles in time, 1986 and then the late 1990s, deflation impact typically occurs with a lag of one to three years, depending on the market, the maturity of the local market, regional market. I think our historical analysis shows that our cash costs should be able to come down 13%, 14%, and 20% deflation for capital costs by 2017. We think the developing costs for new projects which have the rigs in there, we think they'll deflate by as much as 20% to 30%. Of course, it's much less for projects where we've negotiated the prices during the term, but with these things like Mad Dog coming up, and these sort of just started projects, I don't think we've seen the end of the CapEx. I know you're trying to look for what is the CapEx level to model 2016 and 2017 for the same level of activity. I think we're not quite sure there ourselves, but we are seeing this deflation come through. We're going to continue to drive it. I can give you some color so far. We have seen about a third savings on subsea installations at Thunder Horse in the Gulf of Mexico expansion project for example. We've seen 30% rate reductions for the North Sea Mungo field drilling. We've seen 20% reductions from Sumitomo in pipes and pipelines, back to 2009 pricing levels. About a 20% savings of the subsea hardware for Egypt in the West Nile delta project we talked about before. So, and I've got a number of other examples here. 10% rate reductions on well services, 20% down on tubulars, and these are still moving. And some of them were locked in before but these are the new ones, and as time goes forward we're going to see these come through. I think we're seeing a big cost re-basing of the entire oil and gas industry now. And we used to make money at $60, we used to make money at $40, we used to make money at $25, but it's going to require this re-basing of costs which I think is now firmly in the whole industry's sites, Chris.

Okay. Thank you.

Chris, and then in terms of guidance, no major changes from what we laid out for you at the start of the year other than the capital piece we gave you which is we said before we'd said around $20 billion as we were sizing the program for this year. We've seen the deflation come through as Bob just described. We're still in the middle of our process so we're now confident to say it will be below $20 billion for this year. In terms of production guidance, it still remains broadly flat with 2014 is probably still appropriate. That said, I think the 2Q turnarounds went extremely well in terms of bringing that production back onstream, especially in the Gulf of Mexico. Reliability has been running well. Again, that gives us some confidence in terms of the piece Bob talked about around the turnaround programs historically. But then we also have the hurricane season which we know 3Q last year was not that heavy a downturn in terms of volumes as a result of hurricanes. I have no idea what will happen through the third quarter, and really that will probably determine where we end up in terms of this year versus last year. But I'd say broadly flat is still a good recommendation. There may be some upside, but a lot of it depends on the hurricane season.

Okay. Thanks. And you would say all the other items as is?

Yeah. No other changes other than what we've already flagged on capital.

Okay, and just on that point, would you be advising us against, strongly advising us against annualizing your first half $9 billion plus?

I always try and strongly advise everyone never to take a quarter or half year and multiply it by the remainder of the years. But I think below $20 billion is now a confident – I can confidently sit here and say we believe it will be below $20 billion.

Okay. Thank you.

Turning next to Lydia Rainforth of Barclays.

Thanks, Jess. Good afternoon. A question just following up on Chris' actually. On the cash costs, Bob, when you're talking about those being able to come down 13% to 14%? If I look at the chart that you showed, it does have 2015 first half being similar to first half 2010 and yet the production base is close to 30% lower than it was at that point. So is that 13% to 14% on a unit cash cost basis that we're looking at? And then secondly, on the chart of the renegotiations that you've had so far, what percentage of contracts does that actually cover that you renegotiated? And the final one is just on the dividends, and just when you say dividends and focus on rebalancing the financial framework, is there anything on a two to three-year view that you think will stop BP from being able to rebalance that financial framework to be able to support the current dividend? Thank you.

Yeah, Lydia, on the cash cost question, what I was referring to, sort of our historical review of the deflationary cycle, that if you look over time, unit costs come down 13%. So that's a little bit of a theoretical point of looking at history of what we've seen in the past during downturns. To be honest, our company became overly complicated by necessity after the accident. We put in place multiple safety, operational risk organizations, parallel review processes, decision-making, that I think we have our confidence back now and I think we have even greater potential to reduce our cash costs going forward. So one was theoretical based on history of the industry, and I think ours, you'll continue to see them come down. On the dividend.

Yeah, in terms of the dividend, it really is a base of, as Bob said, this industry works at $25, $40, $45, $50, $60 a barrel. It's a question of how fast you can get deflation back into synch. We've got a very strong Downstream business that's very cash generative right now. The Upstream is cash generative – very cash generative in the second quarter. We were actually surplus cash in the second quarter with the – and actually, our net debt came down as a consequence. That's no indication for the next two quarters. We continuously look at what the trend is on deflation, but one of our primary goals going forward is getting everything back into balance and ensuring we can support the dividend that we have in place today.

And Lydia, just to clarify, the cash cost chart is absolute cash costs and it looked flat in 2014 because it's only the first half of the year. In fact, we did see a reduction in cash costs in 2014, which was weighted to the second half of the year. Moving on now to Fred Lucas of JPMorgan.

Thanks, Jess. Afternoon. Bob, a question around the potential for further structural change to your Upstream portfolio. As you look through your lenses into a lower for longer price setting, where within your Upstream portfolio do you think BP is either over or underexposed either by geography or asset type?

Well, Fred, I think it's a little easier to answer after the $45 billion of divestments. So we have a lot of it that's moved away. I think where we can always add to, I'm not saying we're underway, but we can focus on and should focus on is near-field opportunities around our existing hubs and infrastructure. That's clearly a real opportunity for us to focus on. Mad Dog is an example of that. In fact, some of the Russian projects there near infrastructure is another example of it. I think the portfolio we've built over the last three years in terms of shrinking it down and compacting it is actually pretty balanced. I don't see an area that I feel like we obviously need to move away from because it's high-cost. I would feel differently if you were asking me that question with the portfolio of three years ago. And right now again, it's the value. If we see the value in all parts of the world around something that fits the portfolio, we won't stop there. But you won't hear me say something like, well, I think we need more LNG, or I think we need more conventional or unconventional gas. I think it's really just how the opportunities put themselves up. And if we've got a strong balance sheet – we've got certainty now in the payments in the Gulf – we can rebase the cost structure of the company. I think we'll be well-suited for opportunities when they come along and I think there will be some.

Okay. Thanks. Second question for Brian, please, around cost deflation. It feels like were you to re-present the chart you've shown us today in six months' time, those bars are going to get broader and move deeper, i.e., deflation is still building and I think you said so yourself. If we just draw a line through the middle of those deflationary numbers today around 20% and assume not too much of that is getting caught in the CapEx budget for 2015, why wouldn't a CapEx budget of $15 billion be appropriate and realistic for 2016?

Is that for the Group, Fred? Or for Upstream?

That's for the Group.

Yeah. That – I don't think you'll see that level of deflation coming in. On the cost base, I think we've still got more to flow in the second half of the year, hence why the bigger restructuring charge we've taken. So I think there are more costs on the RevEx side to come out. I think on the...

Is it just CapEx here...

Yeah, now I'm just thinking – yeah. But on the capital side I think it's now into the tough decisions about – I think over the next 2016, 2017, 2018 and even 2019, those projects are baked in. Bob talked about some deflation even we're seeing in those existing projects like Shah Deniz Phase II and Oman Khazzan and West Nile Delta in terms of Egypt. But then we get into some hard decisions about the growth of the company beyond 2019 and making some of those tough choices around capital versus rebalancing books. And I think around where the market is today, around $60 a barrel, I think we can comfortably do both. I think $15 billion would be way too low, not that I want to give you guidance now for next year, but we'll need to see where the deflation comes out this year and then give you some further guidance as we go into the first quarter of next year, Fred. But I think $15 billion would be way overcooking it in terms of what we're seeing in the market.

Fair enough. And just finally, tactically, do you yet have a line of sight to see or say when you think deflation might peak? I'm just wondering tactically when we might start to see you get closer to more project sanctions around the bottom of the deflation cost curve?

Yeah. That's a great question, Fred, and I think you'll see more of that as we go through the third quarter results in terms of the bottoming out of deflation. But I think it's just too soon to say.

Do you think we might bottom out before year-end?

Couldn't tell you, Fred. It depends – tell me what the oil price is going to be.

Current oil price?

I think you won't see it bottom out until next year.

Yeah. That's probably about right. Yeah, I'd agree with that.

Okay. Thanks very much, guys.

Thanks, Fred. Next question from Biraj Borkhataria of RBC.

Hi. Thanks for taking my question. Most of them have been answered but I had one on your comments on a strategic shift to gas. Maybe you could just give us your outlook on LNG and how you see that fitting in your portfolio? And in particular, how you're assessing potential new projects in LNG? Thanks.

Yeah, Biraj. LNG economics have been challenged, but there's real deflation coming down now in some of the LNG projects. We haven't – we've just started the front-end engineering to decide whether or not, down the road here, to FID the Browse Project in Australia is one, but we've already seen indications of significant drop in the CapEx projects. The other ones that we have, and we have also been waiting before we take the step, but for example the expansion of the Tangguh project in Indonesia, the third train on that, I think by delaying and not moving forward so fast, we're going to see deflation come through in that and we'll consider that as an expansion sometime next year. But these are exactly the kinds of projects that are going to allow us to fine-tune and make decisions and have options for the future. I do believe that gas demand, we're going to see – by 2035 – we're going to continue to see the growth in both gas and oil. There's no question there's going to be demand that will be out there, in Asia in particular, for these LNG projects. It's just a matter, I think, of getting the timing right and getting the costs right. And I'm hopeful that next year we get on the Angolan LNG project, which has essentially been built; it just needs to be refined and get that on as well.

Thanks. Very helpful.

Thank you. And thanks to all those that are still waiting patiently. We will try and get to you all. Alastair Syme from Citi, are you still there, Alastair?

Yeah. Thanks, Jess. Can I ask a couple of short questions on dividends and returns? I think in an earlier answer on dividends that they were put in the context of the cash balance. I'm wondering if you could put them in the context of through-cycle returns. And so put another way, what return on assets do you think are needed to be delivered in the investment cycle to support and grow real dividends? And then the second question, given your framing on oil prices probably are at the more conservative end of the industry, where you joint venture with other companies, do you think your approach or criteria is making you move forward at a different pace than of some of your peers?

So Alastair, on the first question, I think long-run returns can only head in one direction from where we are given what's happened to costs. And having gone from $100 a barrel down to $50, obviously you've got the big chunk of revenues missing. But as we now start to focus on the projects the Bob was talking about, they're naturally going to be biased towards higher returning assets versus where the portfolio are. So that will be a big focus and that is what will give us confidence to ensure that we can continue to underpin the dividend going forward. So returns is a big part of what we're looking at in terms of the current portfolio of projects, and those things that we'll pursue over the sort of near term and medium term, with a very keen on the long-term future and long-term growth of the company.

Alastair, your point about oil prices, I mean we may have been bearish. I sort of feel that we're not alone now for sure. What we're finding in our joint ventures and even consideration of new projects and concepts and working with the engineering teams, whether it's Mad Dog with BHP and Chevron, for example, great partners. I think everybody is now looking at costs very, very hard, driving it through in the capital costs. The suppliers are moderating. So I don't feel that we're having a difficult time sort of slowing things down or moderating pace, other than the fact that we're driving very hard in our joint venture projects to make sure the cost structures are changing. So, I don't feel like we're out there on our own now, Alastair. And, I would say, that the approach of rebasing the cost structure and for us, simplifying BP, which is something we really need to do and have been working at very hard, it's a good for all seasons thing in any case.

Can I come back to the first question just briefly? I mean, if you look across BP, there's sort of a dividend payout, I guess, you sort of measure against operating cash flow higher than it used to be. Is the implication that your hurdle rates on your investment is also higher than it used to be?

I think in terms of how we look at the hurdle rates going forward, we're still working on the same range that we had historically. It's more about how the cost base now catches up to where the oil price is. I'd actually argue, Alastair, that you could say that certainly for the sector and for BP it's for different reasons, because we sold off a big chunk of high returning assets. But the sector is trended to 10% returns at $100 a barrel, which tells you that the cost base was above $100 a barrel or more capital was being layered into future investment that wasn't in service. I think as we start to correct the portfolio going forward with a focus on the lower capital appetite being driven a big chunk by deflation, some activity, you'll start to see those returns drift back up again. But that is one of the main drivers that we see over the near to short term.

Thank you.

In the U.S. now, Asit Sen of Cowen & Co. Asit K. Sen - Cowen & Co. LLC: Thanks, Jess. Good afternoon. Two quick ones. First on Lower 48, Brian, thanks for providing all the information on the financial data, particularly the production costs for BOE. Just wondering if you could provide us with the DD&A per BOE for Q1 and Q2, if possible. And second, doing quick math on Downstream free cash flow for the first half of this year, and using sort of a historical Downstream DD&A and a tax rate of 35%, looks like around $3 billion in free cash flow – fairly impressive. Thinking about potential upside outside of the macro, could you talk about where we are in the multi-year $1.6 billion cash cost efficiency program? And also, any thoughts on the impact of the China PTA plant that's just about started?

So on the first question on Lower 48, we don't provide the DD&A data, hence why it's not the updates. So that isn't something that we include in disclosures right now. On free cash flow, that's your – I'm guessing that – they're certainly not our figures because we don't give you free cash flow figures by sub-segment. We look at those at the segment level, but you're right. The Downstream is a very strong free cash flow accretive part of our company and has been through the cycle. It's one of the parts of the business that we run for cash and therefore, is free cash accretive. And then in terms of the $1.6 billion efficiencies, Bob layered out I think in his presentation different components of how that's now starting to flow through and we have seen that flow through the first half of this year.

Yeah. Asit, now, on the $1.6 billion restructuring in the Downstream annual cash cost efficiencies by 2018 versus the 2014 baseline, and where we are in that. I'll just note that these restructuring programs, a lot of them have to do with labor flexibility and geographies. And labor flexibility and ability to restructure sort of quickly is faster in the U.S. It's faster in the U.K. It takes longer in Europe. So, I think we've got restructuring going on in both those areas and I think it's going to be first in North America, U.K., and then following on in Germany, primarily. On the PTA plant Zhuhai it's an incredibly efficient project. This is probably one of the most energy-efficient projects. It's got a capacity of 1.25 million tons a year and we use one of our proprietary technologies that are there. It's called ISOCS. It's probably going to have the industry-leading manufacturing costs. PTA has been overbuilt. It's an industry that's been somewhat stressed, but I think this is a really nice addition to the industry and should be what – probably the most efficient unit possibly in Asia – in the world. I don't know if that helps, Asit. Asit K. Sen - Cowen & Co. LLC: Yep. Thank you so much.

Okay.

Thanks, Asit. Next, Lucas Herrmann of Deutsche.

Jess, thanks very much and gentlemen, thanks for all the comments this afternoon. Just a couple of quick ones if I might. Firstly, Bob, going back to Mad Dog, did I hear correctly that you mentioned costs have fallen by, I think, 50% from the original costing? And from memory, the original costing of it was $14 billion, so you're suggesting that, that project now is trending around $7 billion? Secondly, could you just talk a little bit more about the Gulf and your production kind of expectations, aspirations this year going into next? And I guess I'm just glancing back at the Sundry presentation two years ago when I think you intimated the Gulf, including that's sort of after removing the disposals you've made, would be doing somewhere around 260, 270 this year and just whether that's realistic number or ambitious now. And maybe contrast it a little bit with what's going on in the U.K., where the performance appears to have improved fairly markedly over the course of the last six months. We're seeing good volume growth. And sorry, finally, just since you mentioned Zhuhai, does it make a profit at current PTA prices or will we just be looking at a cash contribution at this stage?

Right. Okay. That's a wide spectrum there.

Lucas, let me take up the last one because that's probably the easiest one. We don't give you profitability by asset but it would certainly be cash accretive.

All right, Brian. Thank you.

Yeah. That's right. It's really just come on in the first quarter but yeah. Now, Mad Dog, it depends on the point in time, the 2014, but at one point in time, sometime probably 2010, 2011, the Mad Dog cost estimates were as high as $22 billion for the project. It's been recycled now and I think all I'll say, because we're still talking about it with partners, but it's $14 billion down in December of 2014, and we now believe we can get that project done for under $10 billion. And in the Gulf of Mexico, we – I don't know if we gave it out exactly what the full year was last year – but the fourth quarter, 260 or so. Going into this year, the first quarter, above 250. We've got the turnarounds going on right now. I think the growth will come through the Thunder Horse South expansion down the road, the Thunder Horse water injections. We've got the Ursa Mad Dog recoveries out there. I think being able to keep this running and getting up to 270 by 2018 is very much in our sights. And the Gulf of – or sorry – the North Sea, which was, as many people said, the problem child of the offshore oil and gas industry globally because the efficiencies which were running around 65% a few years ago as an industry, for us, we've taken our plant reliability up from 75% in 2012 up to around 82% now. And on the Norwegian side in 2012, we were running about just under 70%; now we're up to 92% so far year-to-date. So, the North Sea is a very challenged, mature basin that is responding very, very quickly to the challenges here. And I think reliability for the industry is going up.

Okay. Both of you, thank you very much.

Our next question from Gordon Gray of HSBC.

Hi, gentlemen. Just one thing left to ask, actually. If we take aside the strength that we've seen in refining margins, you have a Refining business which is top quartile which is running at 94% utilization. Is this as good as it gets, i.e., what other levers do you have for when margins inevitably do come back for improving the underlying performance of that business further?

So, you're right to flag that actually is running at a very high utilization. There may be still some more road to travel in terms of across the whole portfolio. Some of those assets are operating at 98%, 99%, so right at the top end. So there's still some room for improvement. But there's other things around commercial performance inside those refineries – how we set them up to run the commercial side of it and then how we interact with the trading business. So I think there is still road to travel in the Downstream. If you look at what Tufan's done with the business both in terms of cost, but also on the revenue side. So, I think you're right to flag it. It's at the top end, but there are some assets performing significantly above that and therefore, there is some more room to travel.

Okay. Thanks.

And, the fuels marketing outside of that, the networks, the retail networks, there is efficiencies still to come from that part of it because we think of it as a fuels value chain. But it's great to have these assets running at 94%. This is really – this is what we want.

Yeah, absolutely.

The next question comes from Anish Kapadia with Tudor, Pickering, Holt. Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP: Hi, good afternoon. Thank you. I was wondering if on the cash flow side of things, you saw underlying cash flow lower in 2015 than 2014. And, I guess, kind of looking back at your 2014 targets, I saw that your underlying earnings were 14% below your target, but your cash flow was 9% above. So I was just wondering if you can explain that and were there some one-off positives on the cash flow side last year that won't be repeated this year? Secondly, just on Angola. I was wondering if you could confirm that the 2015 pre-salt wells that you we're drilling were unsuccessful. I haven't seen anything around that. Just wondering how the outlook for Angola looks now given some disappointing exploration and probably kind of having moved through the infill drilling and part of that program? And then just a final question was on, you mentioned moving up to ten rigs in the U.S. Just I'm struggling a bit with the rationale over there when you're seeing just over $25 per barrel liquid realizations and $2 gas realizations? Thank you.

So maybe on the first question on the operating cash. You may recall that in 2014, we did have a $2.2 billion working capital release which underpinned the operating cash flows for last year. This year, so far in the first half of the year, we've had a $1.4 billion build; so that's a swing of somewhere from $3.5 billion to $4 billion just on working capital. I'd expect the $1.4 billion build to be released through the second half of the year. On underlying operating cash flows, if you adjust for the environment for the price, actually they are coming through year-on-year stronger, in terms of if I go back and look at base revenues across the businesses, correcting for the environment and the oil price. So, actually we are seeing a strong set of operating cash flows coming through this year. That will get stronger as we see the costs flow directly through to the bottom line and through to cash in the second half of the year.

Yeah, and Anish, on Angola. We've drilled two years here, two wells in Angola this year, Katambi and Pandora. They're both still under evaluation, so I think best not to comment on that; we're working with partners on that. And on the rigs in the Gulf of Mexico, we have eight running now in the Gulf of Mexico. They are – we've got a couple of them working on the Mad Dog, we've got a drillship working on Atlantis, we've got another working on Atlantis. I mean, these are high performance wells for us. We've had one exploration rig that's been working on Hyla (1:39:19) sidetracks there. And we've got three of them working on Thunder Horse. So I'm talking about in the Gulf of Mexico which is your question, yeah.

Did you ask a question about Lower 48 as well? Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP: Yes. No, sorry, I was actually referring to – you mentioned you're up to 10 rigs on the Lower 48 – and I'm just wondering given where the realizations seem extremely lower at $25 per barrel liquids realizations. So I'm just wondering how it makes sense to do that.

I think the big change that we're seeing there in terms of Lower 48, is a 50% reduction in the drilling costs. So as we brought those drilling costs down, Dave and his team have been able to ramp up the number of rigs we've actually got working down there. And if you then look at the basins that we're in, that actually changes the profitability of the portfolio that we now have in the Lower 48. So it's absolutely being driven by the fact we reduced the drilling cost by 50%.

And I think a big focus on the Anadarko and Arkoma Basins, which – where we get nearly 20% liquids from it.

Okay. Thank you. Stephen Simko of Morningstar in the U.S. Are you there, Stephen?

Hi. Good afternoon, everyone. Just one quick question as it's getting pretty late. When we look at – or thinking about Downstream CapEx and where it's going to trend with the commissioning done and the recent spend levels that have happened over the last 6, 9, 12 months – what would be the right way to think about past 2015 as far as what the kind of base case spending level would be as well as any adjustments you might make depending on commodity price movements from here? Thank you.

We don't typically publish CapEx by sub-segment but you're right to flag the fact that Downstream's capital is significantly lower than the most recent run rate. With now the Whiting refinery fully commissioned, the capital has come down quite significantly and I think you'll expect to run at around about the levels that we see today. We'll look at strategic opportunities in terms of infill, as Bob described, around the fuels marketing business. As opportunities arise, we'll look to do that, but I don't think you should assume any more big projects on the refining side in terms of Downstream over the short to medium term. We're pretty comfortable with the portfolio that we have. So you're right to say CapEx will be trending lower, is lower this year, but we'll continue to look at opportunities going forward.

And in addition, the Zhuhai project is also completed, so there's a couple of big projects that are now onstream.

Thank you. Richard Griffith of Canaccord.

Good afternoon. Sorry to drag you back to the cost issue, but I was just wondering. You've talked a lot about the deflationary environment but I was wondering to what extent are you going to be able to lock in any structural changes from simplification, standardization, et cetera, that a lot of players have talked about in the industry, as opposed to us just going through a more cyclical downturn that may inevitably go back up with a higher oil price.

Well, Richard, that's exactly the questions we ask as we go through the changes that we're making. We have structural changes, organizational structural changes, that we're making to simplify the structure that we think will be sustainable, most certainly, in the Upstream. And so, that again is good for all seasons here. We've become very complicated, so reduction in terms of decision-making, how we do it, numbers of people to get things done, we think we have a lots of room. That's absolutely sustainable. I think the deflation, once we move this in, there are elements of it that may not be sustainable because that's what history shows in a commodity with a cycle, but we're working to change our company to make sure we're not so complicated. And standardization is a very good point. I mean, we've, as an industry, have wanted to design serial number one for many things on many platforms for some time now. I mean, we're driving now a single kind of wellhead that we can use in different places around the world. Standardization of equipment, standardization of activity and that's starting to link up between the companies as well. So there's a period of time where everyone had their own way of doing it. I think people are moving very, very quickly now, and we're part of an industry group now working on standardization of some of the big pieces of equipment to try to do just that.

I'm sorry to come back, just if you took Mad Dog Phase II as an example, what proportion of that 50% capital reduction you've talked about, be equivalent to the standardization simplification as opposed to some of the more cyclical factors?

Well, some of it is the big scope of the project itself; I mean, what we were trying to do. We've looked at simplifying the design, the requirements, the wellheads, even the phasing of the project, looking at Far East fabrication options. I think one of it is a big change in scope and the second part of it is just agreement of what we've learned over the last few years on standardizing wellheads, equipment, drilling, completion designs, that sort of thing.

Okay. All right. Thank you.

Thanks, Richard. Jason Kenney of Santander. Are you there, Jason?

I am, and good afternoon. Thank you. I appreciate your time. I'm going to ask my quarterly question on Russia if I can. So I can understand the year-on-year downshift by about 50% for the Russia division, but the second quarter versus the first quarter is up 2.8 times. And if I remember correctly in the first quarter, you said there was already big FX support in the first quarter. So I'm still struggling to get how that Russia divisional number comes in and I appreciate that you still got sensitivities because Rosneft hasn't reported.

Yeah.

So the second...

Go ahead.

Yeah. The question if I just ask you that as well, on the U.S. Gulf of Mexico settlement, I mean, you mentioned you're going to be paying something in the coming weeks. Should we be thinking of – that kind of annual number that was defined in the settlement press release – should we be thinking of it as an annual payment, a one-off annual payment, each third quarter reach fourth quarter or is it something that is paid quarter to quarter to quarter for the next 18 years?

So, let me pick up the Rosneft question. It's probably the easy one of those, Jason, in that we can't really provide any detail. But the components that would make up the mix are our estimates of what we can see, and of course, it's really for Rosneft to sort of come back with the actual breakdown. The different components 1Q versus 2Q will be around when we know the euro's price improved so that's out there. You can catch that. You know that there'll be a positive duty lag given what happens to the oil price through the quarter versus previous quarters. You'll then – we've made estimates of what we think the ForEx hedging piece will do around that debt book in terms of what they laid in place around ForEx accounting. And then there'll be other movements around provisions. So really, it's a question for the Rosneft results, but they're the big components that we can see moving around that would explain the result quarter-to-quarter based on our estimates. That will be the sort of first point. On the second...

Are we going to be able to get a rule of thumb for that?

That's really a question for Rosneft and I think that's highly unlikely given the amount of moving parts. It's difficult enough trying to get a rule of thumb for our own portfolio, never mind for that piece.

One of the – Jason, I'll just put a footnote on what Brian had said here. The duty lag, which is really not always easy to model, we have exactly the same problem, not a problem with TNK-BP, but what happens is in Russia the duty lag means that the tax preference price is set the quarter or a period of time before the period measured. So, when production falls, it often gets hit with a higher duty percentage and then when production rises – or oil price rises – the tax payments of the duty is essentially lower per barrel. So, as we've seen in the second quarter versus the first quarter, we've had a rise in the price which has led to lower duty than what you would use as your rule of thumb. So, it's a rule of thumb but it's also sort of having to watch the delta in the oil price and it is tricky. It is tricky. We had the same problem always projecting TNK-BP.

Got you. Okay. Thanks.

And then in terms of the settlement, Jason, there are four big components to the piece. The first one is around Clean Water Act fines and penalties which has the 15-year payment schedule starting 12 months from when the consent decree becomes final. So, if the consent decree were to become final in February next year, the first payment would be due 12 months from that date. So that'll take you to February, 2017. That's how kind of how the Clean Water Act piece works. The same thing is in the natural resource damage assessment, exactly the same breakdown. It will be 12 months from the consent degree becoming final and that will then set the trend for future payments. In terms of the state, it's a little bit more complicated so I'll come back to that. And then in terms of the locals, the various local government entities, as we've announced in today's results and was announced by the court yesterday, we did issue the court yesterday via phone call that we were happy with the – and satisfied with the various releases we've been given by the vast majority of local municipalities – and those payments will now start progress over the next few weeks. And those payments we've made directly from the trust fund that was put in place. In terms of the state settlements of $4.9 billion, structured slightly differently, where $1 billion will flow when the consent decree becomes final. Again, that will flow from the trust fund and that will be paid to each individual state along a specific formula. And then, there is a series of payments to take you out to, from memory 2031 or 2032, over 18 years from where we are today in terms of future payments on a yearly basis that effectively become an annuity in terms of cash flowing into those five Gulf states around these state benefit claims.

Okay. Thanks.

Thanks, Jason. And now Neil Morton of Investec. Go ahead, Neil.

Thank you, Jess. Good afternoon, everybody. Just two questions left, please, I guess both for Brian. Firstly, you mentioned about this removal of uncertainties post the settlement having changed your perspective of the gearing band. How does it change your view of the $33 billion of cash on the balance sheet? And then just secondly, in terms of tracking your cash costs and the dividends in the past, you used to flag a couple of lines in the income statement, the production expenses and the distribution and admin expenses. Can we still use those as reasonable proxies for your evolution of cash costs?

No, and I'll come back to why, because there are so many moving parts in those costs. What we track – I'll actually take that one first – we use a subset of what, one is you'll still see those reports in the annual report and accounts. I can't remember where they are but its way deep inside the document you'll find them reported. There are so many moving parts and variable costs inside those. We take a subset of those costs, which are the ones that we performance management and they're the ones that you see where we see the $1.7 billion reduction. That is actually consistent with what we said historically in previous – when we've set targets around cash cost reductions. It's the same subset of those. But you will be able to track the high-level numbers. If they come down or up, it will be coincidental with the programs we're doing. It shouldn't be an indicator of whether we're driving costs in either direction because of the variable nature of a big chunk of those costs. And then in terms of uncertainties, our average cost of borrowing is tracking just above 2%, but it's fair to say that you should assume that we would see our cash balances would trend downwards over time as this consent decree becomes final and the need to hold cash will be less of a concern going forward than it has been historically with the overhang of the potential requirement to post bonds against fines which will now lapse as a result of this settlement.

Okay. And is there an optimum level for cash balances across the company?

Yes, there is, and we run that within the financial frame but we don't disclose what that number is. But certainly, since 2010, we now run with a cash buffer going forward. But it would be significantly below where the cash buffer is today.

Great. Thank you.

All right. Thank you everybody. That was the last question. It's been a long call. Thank you for your engagement and your patience. I'll just hand over to Bob to make a few final remarks.

Right. Well, thank you, everybody. You have shown remarkable endurance, persistence and patience which means you are kindred spirits with all of us here at BP. I think the set of results which came out this morning were below expectations, but I think if you step back from it, it's really the Libyan exploration write-offs and you're probably about where most of you expected us to be. We're not pessimistic about where we're going. We think we have got programs going across the company, both not only in the Upstream where it's obvious necessity, but the Downstream and in our corporate simplifications and overhead reductions. We think this is going to serve us well as we go forward. I think operability – we don't often get the chance to talk to you about our assets operating reliably and safely consistently through the quarter – and this has been a remarkable quarter for us. We're never going to be complacent about that, but also we didn't talk about safety. But our safety statistics this past quarter, at least have been as good as they have ever been across the metrics that we measure. So again, we're not going to be complacent on that as well. And thank you all very much. As we sit here I see the oil price is still in the – got a $52 in front of it for Brent and a $47 in the U.S., so we're just going to continue to march on. Thanks for your patience.