Great, okay. All right. Well, a very big hello and welcome to BP's Fourth Quarter and Full Year 2017 Results and an update on BP's strategy. I'd like to thank everyone for joining us here in person in London, here in the room, as well as all of you out there online around the globe. And we have quite a few people signed up, so a big welcome. I know it's very early in the morning or late in the evening for some of you, so a particular thank you to you. I know the markets in general are a little bit turbulent, so I hope we can give you some good news today. Just to remind you, we are a very long-term industry, and we will keep advancing through any rough waters that the markets send us. And I just would reflect on, I think the markets are about the same level as they were in the 1 of January just overall. So before I begin, I need to draw your attention to the cautionary statement. It is long and detailed, but necessary. So please have a read of it when you have a moment. I'm not going to. So here's the agenda for today. And you'll hear from me first with an overview of our progress against the strategy we laid out a year ago. Brian will then take you through the financial results for the fourth quarter and also update you on the strategy looking out to 2021 and beyond. Lamar will focus specifically on our approach to the energy transition and what BP is doing across our businesses to adapt and position our self for a lower carbon future. That will provide you with some wider context for the updates from Bernard and Tufan on how…

Thanks, Bob. Starting with the environment. Brent crude averaged $54 per barrel in 2017 and $61 per barrel in the fourth quarter, up from $52 per barrel in the third quarter and $49 per barrel in the fourth quarter of 2016. So far as Bob highlighted, this year, Brent crude has averaged around $70 a barrel. Henry Hub gas prices averaged $3.10 per million British thermal units in 2017 and $2.90 in the fourth quarter, compared to $3 in both the third quarter of 2017 and the fourth quarter of 2016. BP's global refining margin averaged $14.10 per barrel in 2017 and $14.40 per barrel in the fourth quarter, compared to $16.30 in the third quarter and $11.40 per barrel a year ago. Turning to summary of BP's earnings in the fourth quarter. Underlying replacement cost profit was $2.1 billion, compared with $400 million in the same period a year ago and $1.9 billion in the third quarter of 2017. Compared to a year ago, today's result benefited from a stronger environment with improved oil prices and refining margins. It also reflects progress across our businesses with higher production volumes in the Upstream and continued underlying growth in the Downstream. Looking quarter on quarter, oil prices improved in 4Q. And Upstream production grew with the ramp up of major projects. This was partially offset by exploration write-offs, seasonally lower refining margins, and a weak oil supply and trading contribution. The fourth quarter dividend, payable in the first quarter of 2018, remains unchanged at $0.10 per ordinary share. In Upstream, the fourth quarter underlying replacement cost profit before interest and tax of $2.2 billion compares with $400 million a year ago and $1.6 billion in the third quarter of 2017. Compared to the third quarter, the result reflects higher liquids realizations,…

Thank you, Brian. You heard earlier from Bob about the dual energy challenge. I'd like to return to the topic and share with you our approach to the energy transition and how we're doing this in a focused and disciplined way as part of the broader financial framework that Brian just outlined. Now as a global energy business, we face this dual challenge that Bob spoke of, meeting society's need for more energy, while at the same time working to reduce carbon emissions. Our industry is changing faster than I think any of us can remember, certainly in my career. And the energy mix is shifting towards lower carbon sources. It's driven by technological advances and growing environmental concerns. But in an uncertain and changing world, the key is for our strategy and our investment choices to be resilient to a range of future outcomes. Now as Bob outlined earlier, how we do that is by setting clear strategic priorities and vigorously pursuing these. We also of course consider the timing and implications of changing patterns of demand and use this to plan around distinct horizons. Things we're doing in the near term to make the business more resilient, as Brian talked about, things we're doing into the next decade and beyond to deliver growth, and things we're starting to do to secure our energy future over the much longer term. Now let me share with you how as a group we're embracing the energy transition and outline how we are investing through this multi-decade period. Today as you know, oil and gas accounts for almost 60% of all energy used. That means companies who provide these energy sources, along with their consumers, have an important role to play in the energy transition. Our ambition is to provide more energy…

Thank you, Lamar, and good morning, ladies and gentlemen. Today, I'll provide you with an update on the five-year plan that we laid out last year with a summary of what we delivered in 2017, what this means for our plans up to 2021 and beyond. Our strategy is simply stated. First, quality execution. This is our biggest lever, be the best at what we do where we work. And this starts with, as Bob highlighted, executing safely. Second, growing gas and advantaged oil. Growing both gas and oil, but only those barrels that are advantaged, be it low cost or high margin, creating a portfolio that is resilient to whatever the price environment. And third, returns-led growth. Investing with real discipline in higher quality opportunities that grow value by generating increased cash flow and higher returns. Last February, consistent with this strategy, we set out clear guidance for our plan to 2021. And the key metrics are highlighted on the slide, 5% production growth, $13 billion to $14 billion per annum of organic capital expenditure, resulting in about $13 billion to $14 billion in pre-tax free cash flow in 2021. Now in 2017, we took significant steps I think towards these goals with a very strong year of delivery. First, at the beginning of the year we set out, I think as Bob said, ambitious plans to start up seven major projects. All seven were successfully delivered on average, on schedule, and under budget. In total, from the beginning of 2016 to the end of 2017 we installed more than 500,000 barrels of oil equivalent per day production capacity from our major projects, a very significant year of delivery as we march towards our 2020 guidance of 800,000 barrels per day. Second, we grew production 12% versus 2016. This…

Thank you, Bernard. Good morning. Today, I will provide you with an update of progress against strategy and the key metrics I set out last year. Let me start with a reminder of our strategy, which is to deliver underlying performance improvement and growth, to expand earnings potential and improve resilience, and to further build competitively advantaged businesses across Downstream. Between 2014 and 2016 we delivered $3 billion of underlying earnings growth. And as I laid out last year, our plans are for further delivery of more than $3 billion by 2021, more than $2 billion from profitable marketing growth and more than $1 billion from advantaged manufacturing. We expect to deliver between $9 billion to $10 billion of pre-tax free cash flow with returns of around 20% in 2021. And we do all this with a continued focus on efficiency and simplification and with safety as our core value. Indeed, in 2017 we delivered our best overall safety performance on record. In addition, we are developing new products, offers, and business models to support the transition to a lower carbon and digitally enabled future. So let me now take you through the progress in 2017. The disciplined execution of our strategy continues to deliver results. If you look at the chart on the left, you can see 2017 earnings stood at $7 billion, around 60% higher than 2014, despite an adverse environment impact of around $0.9 billion from narrower North American heavy crude oil differentials known as WTI-WCS. We continue to see the exposure to North American heavy crude as a competitive advantage. And looking forward, expect this differential to recover from it's relatively low 2017 level. You may actually have seen that this differential has already widened last month or so. The result for 2017 reflects $0.7 billion…

Okay. Ladies and gentlemen. Ladies and gentlemen, it would be – we have a reunion right in front of the webcast camera. We have a reunion right in front of the webcast camera with you guys. So ladies and gentlemen, I have to ask you to sit down. I'd be okay if you stayed and talked, but we have thousands of people down the line in both hemispheres and Europe. Welcome back, everyone. Welcome back, everyone, here in the room in London. Before we move to the Q&As, I'd like to take just a minute or two to summarize a few points, just to get us back into the summary here. First, I would like to thank you all for your interest and your attention. It's been a very long haul. We've showed you lots of data information, charts, and slides. And I hope we provided you with a lot of useful information about the business and our direction. I can happily report – maybe temporary, but I can happily report markets seem to have stabilized. Futures in New York are actually a little bit positive in the S&P. So calm down, everybody. And BP is green on the screen, which is a nice surprise. We've just completed our strongest set of full year results for some time. And the momentum we have in the business is giving us a lot of confidence in the year ahead. And beyond that, Bernard and Tufan laid out things going well into the next decade. So our goal here is to keep growing sustainable free cash flow and distributions for our shareholders over the long term. And we believe we're in the right shape to do that now. It's taken a long time, but I think we're in the right shape to do…

So, Theepan, you're in the front row, go ahead.

Thank you. Good morning. Theepan Jothilingam from Exane BNP. A few questions, please. Just one point of clarity on I think the prize is slide 23 and the free cash flow per share. Just wanted to clarify for 2018, is there any sort of working capital contribution or move there? Secondly, coming back to Macondo and the cash outflows. Perhaps we could just talk about the line of sight, the confidence. I know we've had revisions, the update in January. Could you talk about where we are in terms of the business economic losses? And where you see the court settlement process? Can we see line of sight in terms of closing? Then just on the Upstream. It's a great actually to see the data on unit costs and operational efficiency for 2017. And we see the progress on projects. I want to know what the prize is in terms of for unit cost for 2018? And where operational efficiency can be 2018 vis-à-vis 2017? Thank you.

Brian.

Yeah.

Slide 23?

Yes, so slide 23, wherever slide 23 is. Actually for the plans for this year, we've got a slight working capital build. So it goes in the opposite direction. So that number's pretty well-underpinned. So no issues around that. On Macondo, CSSP, and I can go into great detail, I don't plan to now. I think it was all in the release that we put out last year. I think the way to hold it around business economic loss claims is we've taken a further provision this quarter. It's based on what happened in the fourth quarter, which we've been over before, where all the claims that came through were 10 times the average of the whole life of the facility. And we had a particular negative ruling effect, where about $0.5 billion of claims that have previously calculated to zero came back into the facility as a result of the [Policy] 495 overrule by the Fifth Circuit. So take those things in the round, bell claims have gone from 147,000, 149,000 is where we started. We're down to less than 600 claims now to be processed. So I think in terms of materiality, that gives you a flavor of what's there. We've done our best estimate again based on all the information we have, and we've fully provided for that. But we can't give you any further certainty than that, other than to say the 600 claims of the 147,000 still left to process. We have taken a provision against what we think those 600 claims will be, so we're not completely sort of unprovided. And there is a provision across what we expect the final litigation portfolio looks like as well, and we provided for that.

And I think, Brian, just to remind everyone the frame, so we make it easier for you to try to model this. We always keep the Gulf of Mexico separately. We'll meet the obligations of divestments, rather than the rest of the frame that we describe organically, so that you can actually see our response specifically.

Theepan, thank you. On operating efficiency and on unit costs, I think our plan through to 2021 has continued. Unit cost reduction in that plan, as it does, have continued operating efficiency improvement. Remember, we define operating efficiency across four chokes, not just the plant, but the wells, the export system, and the reservoir. We were actually ahead of plan on our operating efficiency metric in 2017 versus our internal target. And over the next several years, on both unit costs and on operating efficiency, we expect to see further improvement. And without giving a specific target for 2018, 2018 will be no exception.

Now I'm going to go back and forth with the line here, so that people will stay with us on the line. So Jason Kenney from Santander, I think up in Edinburgh. Jason?

Oh, hi. Thanks very much for taking my question. Two on the Downstream if I may. Firstly, I just wondered, give us an update on Australia and the Woolworths deal? And any implications financial or otherwise of a delay there? And secondly, what kind of EBIT should we be thinking about in terms of new regional retail positions, such as Mexico or China, over maybe the next three or four years? And then separately, just can I get a bit more information on Senegal and Mauritania? Just when do you think that could be productive or supported for cash over the next five years? Thanks.

Tufan?

On Australia question, Jason, is first of all we don't actually agree with ACCC's position that this deal is going to lessen the competition in the market significantly. And we are evaluating our options for the next steps. Secondly, in terms of impact, you shouldn't expect any impact on our 2021 numbers, because we have other options that obviously we are working on. So I wouldn't expect any impact on large external targets. On the new markets, I think I don't want to give any EBIT up at this point. But those markets, like Mexico is a good example, some of them may be sort of inorganic entries. Then they will have their own profile on it. But I think something like Mexico, frankly to start with last year, we were in negatives, as you may expect. And now we are scaling up. And with scale, profitability will improve gradually. That's how you may want to think about those markets. So I think further we go – in Downstream IR day, I actually gave you a sort of how much of the fuels marketing improvement will come from there. It is not necessarily one of the biggest contributions in this frame. But contribution will be much bigger beyond 2021 obviously.

Okay. The other, M and S?

Mauritania and Senegal. Hi, Jason. I think in Mauritania and Senegal we've had two exploration phases now. Phase 2 has just completed. From those two phases of exploration, we have the potential for two LNG developments at scale. The first being and the most immediate being Tortue. And the second being from a combination of the Teranga and Marsouin, and the most recent discovery, Yakaar, in Senegal, a very giant resource base. We've submitted an appraisal plan for the second part. That will take some time. With regard to Tortue, Jason, the two governments are working together on the intergovernmental cooperation agreement. The key milestone we need to get that done in the next period of time here to maintain momentum. There are promising signs on that, so that's good. We've completed pre-feed engineering. We've got Tortue down in our project list here, as starting up towards the back end of 2021. And we could see an FID for Tortue probably over the next 12 months or so.

So if you – we have a lot – sorry, Jason, go ahead.

I was just going to say, thanks very much. That was perfect.

Okay. So I'm going to ask you all to identify yourselves for people on the webcast. One, two, three, for starters. Okay one, two, three. Jason?

Thanks. It's Jason Gammel with Jefferies. I've got two for Bernard actually, please. First of all, on base declines, significantly better than expectations on results there. And I think you even mentioned growth in the base was 0.6%. Can you talk about what from a process standpoint is leading to this outperformance? And perhaps even identify some of the assets that would be accounting for the outperformance? Second, great result in terms of reserve replacement. I was hoping that you could perhaps identify the areas that had the largest contribution to the reserve adds. And then also perhaps identify any of the reserve add that was just related to the price effect and the year-over-year improvement in prices.

Very good. So thank you, Jason. On base decline, it – I think in our business, we do tend to look at the big, new shiny things. And of course, small changes in the existing base business, as you point out, bring about enormous value. Growth of the base in 2017, and it was growth, I think has come from a number of dimensions. I think focusing the mine needs must (2:00:34) I think is a very important contributor here. In Alaska, the team have held Prudhoe Bay essentially flat for three years in a row at about 280,000 barrels per day, while we have actually removed drilling rigs. So as the capital in many ways has taken away the focus of the team to optimize what they do, has been intense in simply managing the gas, managing the optimization of the fields, a fantastic example. Performance improvement, in the Gulf of Mexico, in 2015, the cost of an Atlantis well was about $100 million. Today it's about $62 million. That's at the same rig rate, Jason. So actually what has been reduced there is the amount of time dramatically to drill these deepwater wells, allowing us to do more activity. And obviously there is technology. We pump 1 billion data records a day, each day, into our proprietary data lake in the cloud, where people have access to that data and using the digital twin that is APEX, allowing them to optimize production. In Trinidad, we thought we had a problem in the start-up of Juniper that we thought might shut us down for about – part of the system down for about two weeks. We ran a simulation in APEX in 15 minutes that told us that the challenge that we had was actually not a challenge. And…

Okay, Christyan, Lydia, and then Bertrand on the phone.

Hi. Good morning, gentlemen. It's Christyan Malek from JPMorgan. Three questions on capital framework, and then, apologies, one on sort of strategic. First, on gearing, do you have – and how important is it for you to lower your gearing to the bottom of the range? You talk about 20% to 30%. If you found an interesting M&A opportunity, would you be prepared to move back up the range or is there a set level you'd want to achieve first? And then on CapEx, I noticed you've gone to $15 billion to $16 billion for this year. To what extent is that delta towards the low end of the range a function of sort of the CapEx efficiency that you've talked about? Or sort of refraining from necessarily sanctioning all the FIDs that you wanted to? Just want to understand what's driven that move to the low end of the range in percentage terms if you can? Three, on cash flow. So in Q3 your income was $1.87 billion. Your cash flow work – so ex-Macondo, working capital, $5.2 billion in Q4, your income went up to $2.1 billion. Yet, you delivered exactly the same cash flow. What exactly is sort of the drag on that cash conversion? Because it feels to me that you've had – well, given you had better Upstream, better pricing, and Downstream sort of underperformed, understanding that mix and conversion? And apologies, finally, from a strategic perspective, the synergy mandate, this transition you're talking about. Are you willing to spend dollars in terms of moving into this transition? So would you scale up through solar? Is there a cap on what you'd spend on M&A? Or is this all going to be organic? Thank you.

Would you like...

Yeah, sure.

Yeah. So gearing is 10 to -- 20% to 30%. It's been with us for a long time, apart from a period of – during Macondo, post-2010, we went to 10% to 20%, because the fairway narrowed a little bit. And we had liabilities that were significantly beyond the capacity of the balance sheet potentially, before we had the big settlements. Now we're back into 20% to 30%. That is a huge amount of flexibility. And 30%, to be clear, has never been a ceiling. As we move towards it last year, as we laid out to you that we would in the second and third quarter. And as the proceeds came in the fourth quarter, that's come back down again and gearing has come down. Actually gearing, it's a helpful part of the frame. The more important thing is the amount of funds you're generating over the extended debt book, because that's what drives your rating. So in that respect, there is a lot of flexibility within our gearing frame. So it's not something which (2:06:02) comes into particular focus. And as I said, net debt came down throughout sort of back end of the year. Capital frame, it's $15 billion to $17 billion is what we've said. We've said between now and 2021, $17 billion is the ceiling, $15 billion may not be a floor depending on where the environment is. This year happens to be, with the projects that we have lined up and where we are – the capital is, we're going to spend a little bit more capital inside Downstream. Bernard's got a little bit more capital efficiency coming through. So the range of $15 billion to $16 billion feels pretty good. We do know that when we put a range out, you'll typically take…

Let me just touch a strategy question. I think it'll be a combination of organic and inorganic, but it'll feel more organic. And the reason I say it is that what we're trying to do is most of the ideas we're working on right this minute have high connectivity to the existing businesses. Yes, it may take some small investments. And we're making these types of investments now, like Lightsource. But if you think of Lightsource, then that potential grows organically in potential concert with Bernard's business and possibly even down the road in the Downstream business. And so they're high adjacency, high connectivity, but we'll have to make some selective inorganic. I think the feel that we're trying to give right now is a wide aperture approach, high connectivity to what we think our DNA is. Inorganic moves that are small in scale versus large in scale. Then we can control throttle and brake pedal as these ideas develop over years, decades possibly.

Yeah. The objective is that they will have economic value to the shareholders.

Right.

That's a guiding star through all this. We may make some investments. But they've got to have that potential. And tying it in with trading too.

Yeah. I mean what we want, we do want competitive investments in the energy transition space that compete for capital straight up with Upstream, Downstream. Conventially, that may take a little bit of time. But those things could come in the years to come.

Lydia? Lydia next. And then Bertrand Hodée on the line.

Thanks. It's Lydia Rainforth from Barclays. Two questions, if I could and both of them related. The first one on discipline of CapEx and the investment decisions. Has that process changed in the last two, three years in terms of actually making sure that the changes that have been made actually stick? And that we don't just go back to, the oil price is a bit higher, we can spend a little bit more? And then related to that, and I appreciate you are only one year into a five-year plan, but given the growth in free cash flow you expect, given where oil prices are, at what point – what do you actually need to seek to trigger that idea of growing cash returns to shareholders?

I think, Brian, I'll start, and then you can. It's become a habit in the company. Capital discipline, cost control is now a habit in the company. And actually this whole team allocates the capital. It isn't like the Downstream gets some, the Upstream gets some. Actually, we all debate it ourselves, together, which is I think now become a habit as well. And that's an important one, because allocating capital in a company like ours is so important. And then we need to keep that discipline and that framework that Brian described uppermost and foremost, not only with just this team, but our teams that work in all parts of the business.

Yeah. And then in terms of distribution to shareholders. I think we've been very clear actually right through the oil price correction, as the oil prices came down for the last three years that the first part is you scrip offset, which we've now done. That's in the fourth quarter. And there is no question this year, as we see the environment improve, and given that we've got things back into balance at $50 a barrel. But we don't want to get a little bit ahead of ourselves at this point in the cycle, given if you look at the outlook. And as you see Spencer's world energy outlook there lay out for you, and we look at the back end of this year, we could see potentially softening in oil prices, probably still above $50 a barrel. But there's no question this year there will be a conversation around distributions and how best do we get those back to shareholders.

Lydia, thank you. Bertrand on the line from Kepler. Bertrand Hodée - Kepler Cheuvreux SA: Yes. Hello, everyone. Thanks for taking my question. First, on in Upstream, you gave a production guidance of an underlying growth of 5% to 7%. But Bernard also mentioned some potential offsetting factors like ADMA-OPCO, Pan America (sic) [Pan American Energy] in Argentina, ACG. So what could be the reported production outcome, if – especially if ADMA-OPCO were not renewed? And the second question is around the potential list of FIDs that BP expect to take in 2018? What could be those?

Bertrand – Bob? Yeah. Bertrand, hi. On your question around the 2018 production guidance, as we said, 5% to 7% underlying growth expected this year. As Brian said in his slide, reported production will be slightly higher than 2017. So we will trend to that. I would in our plan, ADMA expires on the 8 of March. And we have, as you said, Magnus, PAE, and ACG. The combination of those is probably in the range of 120,000 to 140,000 barrels per day in 2018 versus 2017. So you will see a headline growth. You'll see strong underlying growth. And I hope that that gives you a little bit of the sense of the difference. In terms of the FIDs that we expect to see in the year ahead, we expect to FID Khazzan Train 3, the extension of our Khazzan business, which has been very, very successful. We expect to FID a large compression project in Trinidad, two subsea tiebacks in the North Sea, and the next two projects in our series of developments in India. And there may be more beyond that. Bertrand Hodée - Kepler Cheuvreux SA: Okay. Thank you. Just one follow-up if I may. About the potential extension of ADMA-OPCO, what are your plan here?

Well, the ADMA-OPCO, the concession times out in early 2018. We've been in discussions like many, many companies have been in Abu Dhabi. We would like to work there. And ultimately, it'll be a decision by Abu Dhabi itself on which companies they want to join that. We're in the ADCO concession, of course, and that goes out for another 40 years. But we'll wait and see, Bertrand. Bertrand Hodée - Kepler Cheuvreux SA: Thank you.

Now I'm going to start with Jon and then one here and then one here. Identify yourself. Then I'll go over here. One, two, three, okay? So, Jon?

Yeah. Could I ask – it's Jon Rigby from UBS. Can I ask two questions? The first, I guess, people have asked this question around and around and maybe the answer ends up being the same. But I noticed you frame your outlook at a $55 real price, which seems like a reasonable outcome or outturn. But you talk about your business working at $35 to $40 by 2021. So if I was the board of directors and the executive, I'd be thinking about what options and things I should be doing with that implied free cash flow generation, which is pretty enormous by 2021. So rather than talk about what you do this year or next year, can you talk about what you're thinking about in 2021, if indeed you get to that point and both those things happen? The second question is, I'm not sure if I'm drawing two dots together and jumping to a conclusion. But it seems to me you've been in the Upstream very successful in being quite innovative with partnerships. So either way, you've got opportunity but not the skills, or you've got the skills but not the opportunity. You sort of marry those two together with a partner that fits. And when I look at your U.S. Lower 48 business, it seems to me you've done a huge amount of work from an operational point of view to get it right up top-tier. But because of its very high gas exposure, and I take the point that the gas wells can generate high IRRs. But the real prize it seems to me is liquids. So is there any opportunity strategically around that position that you have to move that business on materially over the next few years if you could? Thank you.

Well, Jon, if we are in a world where our breakevens are down to $35 to $40, and we're in a $55 world, we will generate huge amounts of free cash flow. I think what we need to do is get your confidence about the discipline and the direction we're on. And then we'll have all kinds of options that the company can do, among many things, gearing come down, further distributions to shareholders, all kinds of strategic options are out there for us. So I'm not actually worried about that. I think that will be a good world for us to be in. And that's the direction we're heading in. But rather than saying, we're going to do this or that with that extra free cash flow, it's probably too mature – too early. But the board does with the management team constantly talk about that future. And then Lower 48, I mean I think it's a great team. And we've got all kinds of options there too.

Yeah. I think, Jon, much is made obviously of the Permian and the oil and the liquids, as you said. But I think there is some reality also in what the returns are potentially in that business. And we will of course look at all of the opportunities, and we do. We screen all of the new opportunities there today. But I would just maybe give one small example, just to give you a sense of how you don't have to be in a liquids basin to generate enormous value. In 2015, we had very little acreage in an area called the Bossier or Haynesville Shale and we identified this opportunity called SoHa, South of Haynesville. Over the last two years we have quadrupled our acreage position in this play, which is independently assessed as being possibly the most lucrative gas play in the United States. We have gone from zero rigs to six rigs drilling in the play. The 2017 drilling program generated in excess of 40% rate of return at $3 Henry Hub. We went from zero to about 35,000 barrels a day of production in the space of 18 months and can see that production growing to over 100,000 to 150,000 barrels a day in the next four or five years. 400 drilling locations identified and probably, Jon, more than half of the capital into the Lower 48 business going into that play alone, because it is so lucrative. So yes, much is made of liquids. And certainly we look at liquids, Lamar, all the time and look at those opportunities. But just to give you an example how the model that when we separated the business was intended to work, which is the more independent mindset of go capture acreage, appraise, develop quickly, and create enormous value is working in South of Haynesville. So we'll continue to look at liquids as opportunities. They feel expensive when they come on the market and when we can do the sorts of things that we can do. I won't give you an access cost per acre. But I can tell you it is minuscule compared to some of the numbers that are created for other values. And 40% rate of return is 40% rate of return. So it's just another bit of color on the Lower 48 program.

Here one? Thomas Adolff - Credit Suisse Securities (Europe) Ltd.: Thank you. Thomas Adolff from Credit Suisse. I've got a few questions. Firstly, just on your resource base, you've got a big resource base. In fact, the world is resource-abundant. Some of it is stranded, because of fiscal terms, because of technology. And I wondered as far as fiscal terms are concerned, be it in Angola or other parts of the world, what sort of discussions are you having to kind of really unlock this – these barrels? And also if you can comment on 20K psi technology? Does it work now or does it not work? And given that you are resource rich, so is the world, is your disposal plan of $2 billion to $3 billion biased to Upstream resources in the context of a resource-rich world? And then I guess finally, my question is, if there's one key takeaway from 2017, where you went, wow, the wow factor for each one of you, what would it be? Thank you.

That's a lot of questions.

That's a lot of questions. A comment on stranded assets, because I – or stranded reserves. One, you said resources, which is right. Reserves are not stranded. They are economic. And they're determined by the definition of being reserves, because they're economic. And reserves and resources move in and out of categories all the time. Resources, it's not only going to be fiscal terms. It will be technology that will unlock a lot of these reserves and resources. And one of our strategic foundations is advantaged resources. So for us that means low cost resources. So our intention is with these resources to make sure they're low cost, and they will be economic. Otherwise, we won't actually call them resources. But, Bernard, you want to add?

Well, I think you're absolutely right, Bob. And I think one of the things that we spoke about in the presentation there was that, it's not just as we interrogate each barrel in that 48 billion barrels. But the functional performance improvement each day that we get better at drilling wells, building projects, managing base reservoirs, turns a barrel that is uneconomic into an economic barrel. So that is, be the best at what we do where we work, is our – key element of our strategy. In terms of fiscal, I think the new president in Angola is sending some very positive signals about the changes that he's trying to make in that country. I think they're needed. And I think we will look at opportunities differently going forward. So that's great. I think, Bob, in Alaska, the fiscal changes potentially around what has been achieved with the Trump administration around gas, which many people might have thought of as a big stranded asset, may actually come to light in terms of commerciality. So I think governments are understanding. Certainly in Egypt, we have a lot of support in helping make projects economic that can replace imported LNG. Same is happening actually in Libya. So we are seeing changes, but probably the biggest change is within our own hands, as Bob said.

Right here in the front row. Then we'll go over here. And then we'll come back, guys. Okay?

Thank you. So it's Brendan Warn from BMO Capital Markets. I guess back on the Lower 48 and the U.S. tax change and you have touched on it. And now that we've sort of rolled forward to 2021 numbers, I mean where does that business still fit within the portfolio? And when do you start to see it actually generating free cash flow back to the parent? And how you're thinking of it in terms of positioning? And then just further on that point of fiscal change. I mean since obviously the U.S. tax reduction, I mean where does that country now rank? Has it moved up in the positioning? I mean how much more attractive has it made investing into the U.S.?

Maybe I'll let Bob comment on the U.S. investment climate. But in terms of the Lower 48, Brendan, I think it's a great question. The U.S. Lower 48 business generated cash for the parent in 2017 for the first time in many, many, many years. And that is a testament to the leadership of Dave Lawler and his team in the Lower 48 business. We talked about this in Baku. We have a continual debate, and I think it's an appropriate debate, in the company about the right balance between growth in a volume sense, growth in a return sense, and cash flow growth. And in many ways we were having that conversation rather early. I think the entire industry has moved to that conversation, which I think is the right conversation. So it is. And Lamar and I debate this a lot. When you have opportunities ahead of you, 1,300 wells that generate economic return at $3, greater than 20%, you would have to argue that is a good business proposition. At the same time, we want to ensure that it doesn't become a cash sink for a decade, which as it had for many, many years in the past. So that is a debate that we have ongoing all of the time. The good news is that the team continue to bring forward options, which are making that in some ways easier and in some ways harder, because they're actually bringing more and more opportunities, whether it be in the San Juan. We recently accessed some very cheap liquids in the Swoop (2:25:47) area. So that's the debate, Brendan, that goes on continually. But for the first time in 2017, we actually generated a dividend, so to speak.

And about – you asked about the American business system now with lower taxes, what does it mean? This is important for BP, because we have been over the last decade America's largest energy investor, $90 billion of capital over the last decade. That's separate and aside from the $65 billion of obligations with Macondo. So if you take what was one of the highest tax rates in the OECD at 35%, take it down to 21%, this is of course of enormous value to business in many ways. And that present value to BP is affected by this, despite these short term charges and things that everyone's trying to sort out. So it's important for us. There's no doubt we'll increase investments. I imagine I can speak for – because I'm around a lot of the U.S. business community, the regulatory system in the United States is suddenly so much easier. It was becoming an avalanche of regulations in every directions. Permitting required sequential federal and state, and now they're in parallel. Decisions are going to be made faster. And if they're not made faster, then the infrastructure programs they're talking about won't happen. So from a business community standpoint, it's quite transformational. There will be a lot of capital attracted to the U.S. because of that in my opinion, not just speaking from a BP's perspective. I realize I forgot your one question, which we might come back to. You said, what is the wow factor for all five people. But that's sort of five questions. So it depends on the time. So let's start here one, two, three, and then we'll come back.

Thank you very much. Oswald Clint of Bernstein. I'd like to go back to the Upstream, please. Bernard mentioning the growth platform materially ahead of schedule here. So maybe talk about what's delivering that? Is it just excess service capacity that's helping you? And that might stop in the future? But ultimately, with OpEx coming in below your target, with base decline rates better, with U.S. delivering a bit more, feels like you should be maybe increasing your 2021 free cash flow estimates at this point. Is there something stopping you from pushing towards the higher end of that number or potentially increasing it? And then the second question sort of is, Bob, you mentioned this last year I think, about $8 billion into solar over the last decade. And not much really coming out of it so far. So we're going back into solar. Maybe talk about the KPIs or the milestones you're putting in place with these joint ventures and investment opportunities to ensure there's profit coming out, and you can get out in time before we end up with such large numbers again. Thank you.

Yeah.

On the first one around the improvements that we're seeing and the discipline and the environment and the whole conversation about inflation coming back into the system and what happens at $70 oil. We just keep going back, Oswald, to a very fundamental place, which is that we believe that there is an enormous amount of waste, and therefore, an enormous amount of opportunity in the Upstream oil and gas sector as a whole. We believe that 75% of the savings that we've made to date are sustainable. And that about 25% are due to what you would call deflation, unit rate deflation. But we don't see that 75% stopping there. We see more and more opportunity. I'll give you an example. The cost of a subsea well, the equipment, is down by 56% since 2012. Used to cost about $97 million a well. Subsea equipment now costs about $47 million a well. Now is that because there's excess capacity in the system and suppliers are having to reduce their prices? There will be an element of that. But it would be I think misleading to think that's why that cost is down so dramatically. The cost is down so dramatically, because we're taking a very different approach to what we're doing. We're using industry-led solutions, which is a fundamental part of the strategy, which is taking equipment that is available on the shelf rather than building bespoke equipment. We've reduced the cost of our inspections in that equipment by 60%. Simplifying an umbilical scope in Shah Deniz Phase 2 reduced the cost by 42%. We've moved to global competitive sourcing, which is simply expanding our supplier base maybe outside of the oil and gas sector, maybe outside of countries that we normally go to, heading to China for flanges, for piping. 65% reduction in the cost per meter of flanges and supplies. So I think there is enormous potential. I think the savings that we've made are largely sustainable. And we're not stopping there, and we have more to do. And that's why you'll see us continually pushing, particularly on the capital angle. In terms of the target and whether we are ready to change that target, I think it's too early. We're early days. There's a lot – many years ahead of us. We'll probably give an update on the Upstream towards the end of the year. And we might provide a further update at that stage when we have more of a year under our belt. But probably too early. But I'd rather be in the position we're in today than the alternative.

And on the solar point, you'll recall back in the 2000s, the company made big bets and developed over time businesses in biofuels and wind, but solar was one of them. And in fact around 2000, BP had the third largest solar company in the world behind Sharp and Hitachi. Gosh, has the world changed. So we manufactured it. We started in the U.S. We moved to Spain, we moved to India, we moved to China. And it just – solar cells became commoditized and panels. That's not what we're doing today. We learned that lesson really well. So we are working where really inexpensive solar panels can be combined with project developers, who develop these projects very carefully and Dev's [Sanyal] teams have been working on this, where you develop. There's a margin. You design power contracts, you then combine that with places around the world where we're working with natural gas. So I could see Lightsource BP developing solar projects now in Oman, in Egypt, in India, in combination with natural gas operations and our IST trading, electricity trading, and optimizing around the different fuels. That's the model we have. It's a pretty capital-light model. And I think it can be expanded greatly. So that's our direction in solar. And we've invested – committed $200 million to it. That's very different than the building those big plants that we learned a lot from. Yes. Here.

Chris?

No.

Then on this side?

Irene.

Irene. Irene Himona - Société Générale SA (UK): Thank you. Irene Himona, Société Générale. My first question to Brian. So as you progress in the delivery, clear delivery of the five-year plan, how should we think about the group's sensitivity, earnings or cash flow, to the external environment, oil price, refining margin? Is that changing? Not necessarily today, but as you deliver the new barrels with a 35% higher margin, is that sensitivity changing? My second question concerns the focus you all highlighted on modernizing BP, employing the new technologies, digitalization, predictive maintenance, et cetera. And I had two related questions. One is, I don't have a clear picture as to whether that effort is systematically implemented through a process that aims to actually deliver that modernization across your assets over the next N years? Or whether it is more of a fragmented opportunistic approach? And the second related question, from a risk management perspective, these are new technologies. How should we think about the risk? Are we adding a new layer of perhaps unknown or less well-understood risks on top of the traditional risks related to those new technologies? Thank you.

So on rules of thumb, we'll be updating those this quarter. But you can still use something along the range of – and it's going to be a range – $3 billion to $3.5 billion pre-tax, set against $10 barrel movements for oil. And on a post-tax basis, we don't normally give you guidance, and Craig [Marshall] will be horrified for me to even go there. But again, $2 billion to $2.5 billion. It's a broad range. You may as well use the numbers we're using. But $2 billion to $2.5 billion on a post-tax basis. I mean it will depend – the reason why we don't do it is because of course, as you've seen this year, the tax can move around a huge amount intra-quarter. But on a run year over the year, they're probably good numbers to use for now.

On your technology question, it's a really interesting question. I don't think anybody has ever asked that before. It's a combination of both, Irene, which is systematic programs. But we actually studied a lot of how other companies have done this and how they don't do it very well is suddenly mandate on modernization program. What we've done is we've created pockets, maybe it sounds like it's fragmented. But people who have shown what they can do, piloted and shown amazing results. Then the uptake starts occurring all across the company. Nobody wants to be left behind. And it disrupts your existing IT systems. So we've tried to think about this both in a human nature way, avoiding the big company, here's how you must do it, and let it organically grow and spread. And it's spread – that's one of my big a-has, by the way, for 2016 and 2017, is how this has spread. And the amazing enthusiasm of people when they see tools, and young people in the company love these tools, is a big a-ha for a big oil company. So of course we have to system-atize it, as we're doing Upstream and Downstream. But I think letting it spread on its own sometimes is remarkable with standards and with reliability.

Yeah. I was going to say, Bob, just to add on to that, because actually my a-ha or wow for this year is the quality of the people that we're now hiring. They come in and they just assume that this thing, wherever their thing is, will tap into all of your systems. And they can app develop themselves, and they'll disrupt and innovate. And we learned about six years ago that we'd have to have an IT frame that would enable them to still be able to do that but keep the company safe, if you think about the cyber-threats that sit out there and what we do around data lakes. But I'd be in the same – I think they're all the same place actually, the people we're now bringing in, the quality of these people, it's a wow to the positive. And it's also a wow to the wow, because it is quite extraordinary.

I don't know if that's helpful, Irene? Okay? All right. There and then one, two. Two? Okay. Three, okay.

Thank you. It's Chris Kuplent from Bank of America Merrill Lynch. I've got two quick ones for you, Brian, and then one for Bernard, if I may. It looks like 2018, Brian, will be the first year in a long time when depreciation will run ahead of CapEx. Is that sort of going to track each other as we go and look forward into 2021? And then secondly, I hear you don't want to commit on explicit language regarding shareholder returns. But if you were to prioritize, what is going to happen first, the cancellation of the scrip or the buyback running ahead of the quarterly scrip rate or a DPS increase? And the question for Bernard is, one of my favorite projects seems to have made a return onto your slides. So I just wanted to hear how Pike has made it onto advantaged oil? Thank you.

We listened, Chris, you see.

Actually, I'll let Bernard go first.

Go ahead. Go ahead.

I'd like to hear the answer to that question as well. DD&A, it's going to tick up a little bit through 2018. It will probably flatten off in 2019, 2020. The tick-up is of course the new production that's coming onstream, the new reserve adds is obviously increasing DD&A. So there will be a marginal uptick into 2018, 2019, flattening off in 2020, 2021. On shareholder, we've had this conversation. The board, we've had a lot of conversation with our shareholders about the scrip. I think the first test for us, Chris, was – and it's great that people are now asking, well, why do you need the surplus cash? Because two quarters ago they were saying, you couldn't pay the dividend. So now people seem to think we can pay the dividend. And not only have we done that, we've offset the scrip. Clearly, people would now like to know what we'd like to do with any surplus cash beyond that. We've had extensive conversation with the board every quarter around the dividend, which we've done through this whole oil price correction and with the delivery of the 10-point plan in 2014. We'll continue to do that. But I think it's important that we offset the scrip. About 45% of our shareholders will take a scrip uptake. So right now there is no intent to cancel. We do understand though, that there's a friction cost associated with issuing shares and those shares then being repurchased. We think that's worth it, given, A, our shareholders want it. And even in a benign quarter like 4Q, we had a 15% scrip uptake. There were tax advantages for ordinary shareholders. So we want to make sure we maintain that. The key is that we then offset it. And I think having the financial flexibility as to how we self set that through the year. And you'll find that today we'll be back in the market buying. I know people sort of said, well, you stopped on a certain date in December. Well, yeah, because we brought back all the scrip, so we'd offset the dilution, which is what we said we'd do. We entered a closed period, today we're back in an open period, we'll be back in the markets again. So it will be managed over the year. And it creates some financial flexibility for the corporation. But there's been no conversation around canceling it, given the feedback we get from shareholders that they like it, but they want it offset going forward.

Thanks, Chris. On Pike, it's a project that's out there, that's on the possible list out to 2025. I think I'd say a couple of things about it. First is, I think that the reason that it's on the slide is a testament to the great work that Devon [Energy], the operator, has done in driving the breakeven of that project down, I think towards the lower $40s. So it's actually a quality resource that probably has further optimization to be done on it. So I think first thing I would say is that it's – given the quality of the resource and I think the fantastic work that Devon have done, the labor costs in Canada falling dramatically over the last several years, I think it starts to enter into the competitive frame in terms of a breakeven basis. The second thing I would say is that it is part of the 6 billion barrels that I referred to. But not every project in that 6 billion barrels is required. We said we need about 4 billion barrels, if we chose to grow at 1% out to 2025. And we have about six, so there will be choices within that. And Pike may indeed be one of those choices. But I think Devon have done a great job in driving that breakeven down. And I think we are not yet at the stage as to whether we say that's in the base plan for the business or not.

We're running a little over time. So we're going to take two questions and then going to let you go. Martijn Rats - Morgan Stanley & Co. International Plc: All right. Hello. It's Martijn Rats at Morgan Stanley. I want to ask about one of my favorite projects, which is Zohr. In the sense that I do remember that when you announced the transaction there was an option to buy more of it, which I think probably has expired. And I haven't seen an announcement you've taken it up. So I wanted to ask why you decided not to take up the option to buy more? And secondly, I wanted to ask about your ROACE target of more than 10% by 2021. In the spirit of slightly more transparency on tax, I believe this ROACE target is pre-tax. Could you...

(2:42:37) Martijn Rats - Morgan Stanley & Co. International Plc: Oh, that is all pre – okay. So that question answered itself.

And with Zohr, there was another chance to take up an option of another 5%. We debated it, debated it, looked at it in our capital frame. We still think it's a really good project. It was a deeper well drilled. And we just said, you know what? We've got this set of projects that we're investing in this year. It would've taken on a good healthy capital obligation from past costs as well. And so we have stepped back from it. And I'm sure I will have someone take that up. No question about it. Last question, sir? Rob West - Redburn (Europe) Ltd.: Okay. Thank you. It's Rob West from Redburn. I've got to move from questions about projects on your chart to a project that is not on your chart, which I don't actually know is a real project or not. It's Kirkuk in Iraq, where I've seen in the press that there's an MOU for you to double production. I don't know if it's real. I don't know if you can comment on it. But could you in principle and what's holding you back? The second one is on the just incredible reliability. I'm not sure whether to be excited by it or a bit little afraid of it, because once a number gets to 95% sort of level, you start wondering can it keep going up? And if that improvement in reliability has been driving the decline rate down, where are you seeing the decline rate for this year? Is there a bit of bounce back there? That's the second one. And then just finally, really quickly on solar. I love the answer you gave about integrating with the gas business and freeing up those molecules in Algeria to send them down a pipe to Europe. But the thing I was going to ask you is, how much of this move back into solar is about cost? Because when you see the costs of wind, which is where I've always thought about BP being more traditionally focused, where it's a $0.05, $0.06 a kilowatt hour. And some of these sunny countries, you're getting solar out for $0.02 to $0.03. And is that part of what's tempted you back in there, over where you're traditionally focused? Thank you.

Let me take the last one, because we were just talking about solar. So you're right. Solar costs are coming down. The ability to generate electrons in a country and then put the natural gas to power plants, which is often where it's needed, is part of this. Wind, we've been – we have a big wind business in the United States, very big wind business, across 16, 14 wind farms. We have been cautious about getting involved in offshore wind, because the salt in the gearboxes and working over those big turbines because – but that technology is changing. So we're getting more interested in wind offshore. So give us some time. We want to get that right. I think we've been right so far to wait. Kirkuk, Bernard and I talked about this the other day. We have a long history in Iraq. We work in the Rumaila Field, which probably puts 40% of the treasury into the country of Iraq. They've restabilized things up north. We've had an agreement to study the Kirkuk Field since 2013. They've asked us to come back in. We'll see. We know a lot about that. We're certainly not going to jump in with commitments until we fully understand it. But I would take it as a signal that Iraq as a country is getting its feet back on the ground again, pulling it together with the idea they can offer new and different investment opportunities. So we'll see, we'll see. And it would be great if Iraq could do that and if we played a role in that, it was economic, and we're careful, that would be a good thing. Your other question.

Reliability and base decline. Rob, it's a good point. Theory says there's 5 percentage points opportunity. And we're unlikely to get to 100% reliability. We do see further opportunity in plant reliability, but you're absolutely right. It's not going to be significant, but important. But when one door closes, you need to open another door. And the door that we are opening in this space is around operating efficiency. We look at four separate chokes in our production system. The plant, the number that we just referred to, is one. But there is also the export system, and we saw what happened in $40s in 4Q. There is also the wells and the reliability of the well system. And there is also the reservoir itself as to whether it's producing at its capacity. We define operating efficiency very rigorously across all four chokes, 95% times four gives you an 80% type number. So we are actually focused very heavily now on driving our operating efficiency up, which obviously expands our scope, which more broadly, particularly I think, into wells and into export. We have internal ambitions to grow that operating efficiency number over the next several years. Like everything, it's got its challenges, but that's where the opportunity lies. So maintaining plant reliability at 95%, maybe growing it hopefully to 96%, and importantly in our key assets is important. And shifting the conversation into all four chokes and measuring the reliability of the entire system, which is what operating efficiency is, is the next opportunity to impact base decline.

And in the Downstream, we shouldn't forget the availability of the refining system at 95%. It's benchmarkable. The Solomon index, I mean that's a great, great set of results for Tufan and the team. And there are cases in refining if you maintain them and operate them well, that you can maintain 95% reliability for years, done right with the right turnaround. So that's an industry standard to get the right assets that we will strive for.

So ladies and gentlemen, and let me say again to everyone on the line from all over the world, and there's quite a few on the line, I see hundreds in fact, thank you very much for your time. We're here in London. We're going to stop and have a cup of coffee outside. You can't join us, but you'll be there in spirit. And again thank you for your time today. Bye.