英國石油 (BP) 2018 Q1 法說會逐字稿

Welcome to the BP presentation to the financial community webcast and conference call.

I will now hand over to Craig Marshall, Head of Investor Relations.

Welcome to BP's first quarter 2018 results presentation.

I'm Craig Marshall, BP's Group Head of Investor Relations. And I'm here today with our Chief Financial Officer, Brian Gilvary.

Before we begin, I'd like to draw your attention to our cautionary statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our 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.

Now over to Brian.

Thanks, Craig. And thank you to everyone for joining us today.

Before we begin, let me take a moment to comment on the updated format of today's presentation. This time last year, we introduced a new [SCA] which was designed to provide a simplified approach to ensuring key information was presented to you and the investment community in a user-friendly format. Consistent with those changes, we've updated our results presentation to provide a succinct, strategically focused set of quarterly materials that underpin delivery of our medium- and long-term targets set out over a year ago. The supplementary materials contain further disclosures, which together with our SCA provide all of the usual material around our quarterly results.

So starting with highlights of the first quarter. Following a year of strong delivery and growth in 2017, we have had a good start to this year. Underlying profit for the first quarter of $2.6 billion grew by 23% relative to the previous quarter and 71% versus the same quarter last year, making this the strongest quarter for 3 years. In the Upstream, we delivered 14% growth in underlying production relative to the same quarter last year. This growth, coupled with a stronger oil price environment, enabled us to deliver Upstream underlying pretax earnings of $3.2 billion, our best result since the third quarter of 2014 when oil prices were over $100 a barrel. Our Downstream delivered underlying pretax earnings of $1.8 billion this quarter, benefiting from the continuing high availability across our North American refining systems, which enabled us to capture wider light, heavy crude discounts for available heavy crude out of Canada.

We also continued with our share buyback program through the quarter. Since we started the buyback program in the fourth quarter of 2017, we've bought back 69 million shares at a total cost of $460 million.

This quarter, we also published the annual update of our energy outlook, the second technology outlook and most recently our reporting on advancing the energy transition. This report lays out our reduce, improve, create framework, setting out short- to medium-term measurable emissions targets as well as our approach to creating low-carbon business opportunities where we see potential.

In summary, it has been another busy quarter of continuing development and delivery across the businesses. Now before turning to results, we'll take you through our view of the environment.

Brent crude averaged $67 per barrel in the first quarter of 2018 versus $61 per barrel in the fourth quarter of 2017. This reflected continued robust global demand growth building on the 1.7 million barrels per day growth in 2017, a high level of compliance with the supply cuts targeted by OPEC and participating countries and geopolitical concerns about future supply disruptions. U.S. Henry Hub gas prices spiked briefly in January in response to extreme cold weather. The price moderated in February with warmer weather and increased U.S. production, averaging $3 per million British thermal units for the quarter. BP's global refining market margin averaged $11.70 per barrel in the first quarter of 2018, down from the fourth quarter of 2017 but flat compared with a year ago.

Looking to the rest of the year, we expect the Brent oil price to be influenced by the degree of continued production discipline from OPEC and other participating countries, the pace of U.S. Lower 48 supply growth and global demand strength. There remain significant uncertainties, including geopolitical risks and the possibility of further guidance from OPEC as OECD commercial stocks near their 5-year rolling average.

Looking now at the group results for the first quarter.

BP's first quarter underlying replacement cost profit increased to $2.6 billion compared with $1.5 billion a year ago and $2.1 billion in the fourth quarter of 2017. Compared to a year ago, the result benefits from higher liquids and gas realizations coupled with continued underlying performance delivery across the business. In the Upstream, we saw production increase as a result of the ramp-up of the 7 major projects that started up in 2017 and continued strong performance from the base. In the Downstream, we also saw benefits from increased commercial optimization and high Canadian heavy crude oil discounts.

Compared to the fourth quarter of 2017, the improvement in earnings reflects higher liquids and gas realizations and higher production in the Upstream. In the Downstream, lower industry refining margins were more than offset by the benefit from higher Canadian heavy crude oil discounts, lower costs and a lower level of turnaround activity. The group result also reflects a higher overall trading contribution this quarter.

The first quarter dividend, payable in the second quarter of 2018, remains unchanged at $0.10 per ordinary share.

Turning to cash flow and our sources and uses of cash in the first quarter. Excluding oil spill-related outgoings, underlying operating cash flow was $5.4 billion. This included a working capital build of $1.7 billion driven by the increasing oil price and nominal seasonal builds across our businesses. Organic capital expenditure was $3.5 billion for the quarter. Divestment proceeds totaled $200 million. And we made Gulf of Mexico oil spill payments of $1.6 billion, including $1.2 billion relating to the final Department of Justice 2012 settlement agreement. These payments, along with the seasonal working capital build, saw quarter-end net debt of $40 billion; and gearing at 28.1%, within our 20% to 30% band.

As mentioned, we remained active in our share buyback program and bought back 18 million shares through the quarter at a cost of $120 million. While the shape of the program will vary from quarter to quarter, we continue to buy back shares to fully offset the dilution impact of the scrip dividend issued over the year.

Across our operations, we continued to make good progress. 2 weeks ago, we announced a new strategic alliance with Petrobras with a commitment to work together in Brazil on a range of opportunities across our whole business. In the Upstream, our focus on execution is delivering improved performance. Plan (sic) [plant] reliability in our operations was a record 96% in the first quarter. This helped us deliver an operating efficiency of 86%, a 2% improvement on our previous best. In February, we announced the successful startup of the Atoll gas field in Egypt, ahead of schedule and under budget. This gas project was brought onstream less than 33 months after the initial exploration discovery. We've also taken final investment decisions or FIDs on the developments of Ghazeer, the second phase of the giant Khazzan gas field in Oman; KG-D6 satellites, the second project in the integrated KG-D6 development in India; and Alligin and Vorlich, 2 new U.K. North Sea subsea field developments.

In the Downstream, we've continued to make good strategic progress leveraging our strong brands and quality portfolio. In retail, premium fuel volumes grew by 5% compared with last year. And we continued the rollout of our convenience partnership model across our network. We also celebrated our first year of operations in Mexico, where average fuel volumes per site have increased by over 60%. And we recently opened our 200th site. At our Whiting refinery in the United States, we processed over 10% more heavy crude than a year ago, partially capturing the higher light, heavy discounts. And in petrochemicals, we achieved a new production record at our PTA plant in Zhuhai, China.

We have also continued with the development of our alternative energy business with the recent creation of a new Indian joint venture between Lightsource BP and Everstone Capital to create EverSource Capital. This partnership provides us with an interest in an innovative fund management platform for low-carbon infrastructure projects in India, which we see as a market with huge demand and potential.

Before I summarize, I'd like to take a moment to talk about our 2018 guidance. In the second quarter, we expect Upstream reported production to be lower than the first quarter due to the exploration of the Abu Dhabi ADMA offshore concession and seasonal turnaround and maintenance activities. In the Downstream, we expect seasonally higher industry refining margins, a narrowing of the discount for North American heavy crude oil and a significantly higher level of turnaround activity. Our full year 2018 guidance remains unchanged from what we laid out in February. We expect Upstream underlying production to be higher than 2017, driven by the continued ramp-up of the 2017 major projects as well as the 6 major project startups in 2018. Actual reported production will depend on divestments, OPEC quotas and entitlement impacts.

The total DD&A charge is expected to be higher than 2017, reflecting the growth in Upstream production volumes and the major project startups. We expect organic capital expenditure to be in the range of $15 billion to $16 billion, at the lower end of our medium-term $15 billion to $17 billion frame, reflecting the continuing focus on disciplined spend. In other business and corporate, the average underlying quarterly charge is expected to be around $350 million, although this may fluctuate between individual quarters.

In the current environment, the underlying effective tax rate is expected to be above 40%. Our balance sheet remains robust, and we continue to target a gearing band of 20% to 30%. With operating cash flow continuing to grow within our frame and Gulf of Mexico oil spill payments reducing, we expect gearing to trend down through the rest of the year.

So in summary, we've had a good start to the year, with the financial and operational momentum from 2017 continuing into 2018. We will maintain our disciplined capital frame focused on delivering against our operational and strategic targets across our Upstream, Downstream and low-carbon businesses. With growing operating cash flow, we continue to expect the organic breakeven for the group to average around $50 per barrel on a full dividend basis in 2018, reducing steadily to $35 to $40 per barrel by 2021 in line with growing free cash flow. And as we look beyond 2018, we continue to expect to grow returns as we grow our earnings within our disciplined investment framework. While we still have some way to go on returns, we are seeing good progress on the underpinning drivers of improvement.

With the continuing momentum across the businesses and growing free cash flow, we remain active in our share buyback program. With gearing expected to trend down this year, we will continue to ensure the right balance between distributions and disciplined investment.

Thank you for listening, and I'd like to hand over to questions.

(Operator Instructions)

Okay, thanks very much for listening. (Operator Instructions) IR is obviously available after the call to follow up on anything else.

First question then, from Biraj Borkhataria from RBC.

I've got, hopefully, 2 easy ones, but firstly, could you just give us an update on the Woolworths acquisition and where you are on that process? And then secondly, could you let us know if you have any significant maintenance at Whiting this year?

Thanks, Biraj. On Woolworths, there isn't really an awful lot we can say other than the fact that we are in conversations with them and the regulator in Australia around potential remedies and the way forward. So I think there'll be more to follow on that this year, but in terms of on the assumption that, that transaction may or may not close, it's more likely to be towards the end of the year, before anything happens. And indeed I suspect, if there's any cash impact of that, it's more likely to be maybe in the first quarter of next year. But we're working through that right now, and it's a little bit premature to say anything about where we end up to with that transaction. On maintenance schedules around Whiting, nothing out of the ordinary. I think we went through a large one last year at Whiting, around the cokers, but there's nothing out of the ordinary planned for this year.

Okay, we'll take the next question from Os Clint at Bernstein.

I wanted to ask you, yes, some more on the quarter, the Upstream OpEx number ticking up a little bit in the first quarter, a little bit bucking the trend of the broader industry. Could you talk about that number and why you expect it to continue to decrease through 2018, please? And then secondly, just on refining in North America, again I wonder if you could potentially say what type of contribution may have been delivered there from those wider differentials in Q1 around Whiting. Because you talk about it diminishing as you go into the second quarter. Any sort of additional granularity around that would kind of be useful, please.

Thanks, Oswald. The little ramp-up that you saw in 1Q was really around some Gulf of Mexico workovers and well work that we were doing, so we would expect to see that continue on the trend that we've seen. We are acutely sensitized to any signs of inflation at the moment, but we're not seeing any of that come through, certainly not in the contracts that we're looking at, at the moment. So it's one of the areas that we focus on just to make sure that, as these -- as we see these higher prices, that we're going to start to see inflation creep back in. And that doesn't appear to be the case at the moment across the piece as we look to -- look at our contracts for this year. But that uptick in 1Q was purely driven by [Guan] well work. We'd expect that now to start to taper off through the rest of the year and in terms of the costs that you saw come through in the first quarter. And then in terms of North America, of course, refining margins are relatively suppressed in the first quarter compared to a year ago and -- but of course, the light, heavy [diff] is what really sort of uplifted what -- in terms of the refining system in North America, particularly Whiting refinery. And we weren't able to capture all of that because of curtailment issues. And the light-heavy spread opened up off the back of a tranche of production that came on in the Canadian heavy market, and then of course curtailment issues that began to get constrained coming in. So we're not able to capture all of the volume at that heavier discount, but we certainly caught a fair proportion of that, and that's what helped support the Downstream numbers through the first quarter.

Okay, we'll take the next question from Lydia Rainforth at Barclays.

A couple of questions. So just in terms of the share buyback, Brian. And obviously we were running at below that level, and I know that's going to be linked to the net debt side, but as you go through the year and given where oil prices are, that balance between debt repayment and share buyback, can you just talk about how you see that coming through? And then just secondly, in terms of the Upstream production numbers, they clearly have been very good. Is that -- are we seeing sort of again the benefits of low decline rates coming through?

So on the first question. I think we laid out -- with the third quarter results last year, we talked about reinitiating the share buyback to offset the scrip. We knew that we'd have a lumpy series of quarters ahead of us, particularly the first quarter, so what you will have seen in the fourth quarter, we fully offset the scrip dilution from the third quarter of last year. We've partially offset it through the first quarter this year knowing that we had the $1.2 billion cash payment that went as part of the final DOJ settlement from 2012, so we were going to back off a little bit to the first quarter. Now we've gone through that hump, if you like, in the first quarter of those payments associated with that settlement and the usual Macondo payments that are going out. We'll start to ramp the buyback program back up again. And again as we've said before, over time, we'll expect to fully offset the scrip dilution. And we will certainly start to ramp that activity up, and you'll see that this week as we go back to the buyback market. But it was really a function of knowing debt would rise through the first quarter with those payments and the typical seasonal build. What we will now see is net debt -- certainly at these prices, net debt will naturally start to decline. And then that will then get us an opportunity later this year to look at potential further distributions either through buybacks or a conversation with the board around dividend.

And then on production.

On production, I think what you're seeing is, a, definitely in terms of the base, we're still seeing strong performance coming out of the base, this what we've talked about before about negative decline. I think that's becoming more systematic in our numbers, but we'll know more about that as we get through this year. And the projects coming on early and ahead of budget last year has helped. The ramp-up of those projects has gone well coming into this year, and that's why you're seeing actually headline production was up 9% but underlying production was up 14%. And I think it's just a function of the performance of the projects coming on, the execution of those. We've brought on our first project already this year in Egypt in January. And we'll look to ramp up in the 5 projects, and so the 5 projects will come on later on this year. But it really is it's a function of the 2 things: ramp-up of projects from last year and continuing strong performance at the base.

Okay, we'll take the next question from Alastair Syme of Citi.

Brian, can you just -- you -- I mean you've just recently sanctioned the Khazzan Phase 2 project. Can you offer any perspective of around how we should think about the economics of that compared to phase 1? Any sort of high-level comments you want to make?

I think, from memory, I recall that I think there's a third gas train. And a second liquids train will come with that project. And we can't talk commercially about the nature of the contracts, but again it's the gas will go into a domestic gas market. And in that respect, the economics are attractive, robust within terms of what we look at. And especially given what we've learned from Khazzan Phase 1, the optimization that we're able to do around that, it's gives us great optimism around what Khazzan Phase 2 might look like. And it's basically a development that I think give us around 4 discoveries. And we'll be able to utilize existing facilities, so from a cost perspective, that enhances the economics. But there'll be more to follow on that as we go through this year.

Can I follow up also on Tortue, which is the -- I guess, the next sanction in the pipeline? What needs to happen to that to move forward?

We're right -- in conversations right now with our partners in the -- and with the local governments concerned around Mauritania and Senegal. And again, really not a lot to say about that other than the fact there'll be more to come this year in terms of what the phase 1 looks like of that development. I suspect phase 1 may look very different to what the subsequent phases then look like, but we will be looking to move this one forward this year. But we're still in the discussions with our partners around what the final concept will look like.

Okay, we'll take the next question from Theepan Jothilingam at Exane BNP.

A couple of questions. Brian, you touched on the performance of the kit and the growth. I was just wondering if you could maybe quantify how much of the new projects has been sort of installed out of the 900,000 for the 5-year plan and what production is actually delivering into Q1. And the second question was just on the strategic alliance with Petrobras. I think a number of your peers have had similar alliances, and I was wondering. Is the -- with the timing of this, is there something specific BP has identified that they can -- that you can execute with Petrobras? And is that incorporated in the $15 billion to $16 billion of organic CapEx?

So I'll pick up the second one. And I'll ask Craig. Craig will come back on the production numbers in the first question, which he's got there in front of him. On Petrobras, we actually had a meeting of cross-sections of our executive team 2 or 3 weeks back actually and found that there's a big overlap with the DNA. First of all, Petrobras is a world-class operator. There's no doubt about that. And I think we found that across a whole range of subjects, from technology, to sharing people and knowledge transfer, there is clearly a lot of opportunities. And I think you'll see some of those unfold as the year progresses. And actually from our perspective, it's a classic. We talked before about what's really important, what's the differentiator for all of us. It's about technology, and it's about relationships. And it was clear that there was a huge amount of empathy between the 2 teams, which led to the signing of that MOU. And I think there'll be simply more to follow on that as this year progresses. So nothing specific today, but as we explore different opportunities, you'll see more come to the fore on a point-forward basis. On production, Craig...

Yes, on production, Theepan, we laid out, as you'll remember, earlier this year, in February, the 900,000 barrels a day by 2021 of major project production. If you recollect the chart we showed you, it does actually break down into the production that's operating, the production that's under construction and then that production element towards the back end that is yet to be FID-ed. In short, based on those wedges, we'll approach this year around 400,000 barrels a day of that 900,000 onstream and then obviously as we start up the rest of the major projects that are in construction with Atoll, obviously having started up productional ramp-up through next year and beyond.

Okay, we'll take the next question from Thomas Adolff at Crédit Suisse.

I've got 2 questions, please. Firstly, on the Upstream, obviously 1 of the 6 major projects have been brought onstream and again ahead of schedule and below budget, so I wondered if you can talk about the other 5 projects, where they are and whether the better performance is reflected in your cash flow break-even estimate for the group. Secondly, just on technology. And obviously you talk about technology creating efficiencies, but obviously efficiencies also create redundancies, and I wanted to focus on the latter. And I believe you used to have about 25,000 people, employees in Upstream back in 2014. Now it's down to around 18,000 employees in Upstream. And I just wondered how much more effect there is within the organization in terms of people or organizational layers et cetera.

Okay, so on the first one, the other 6 projects which we've laid out for you in the supplemental information and we've talked about in previous discussions, we've got the big one of Shah Deniz phase 2 comes onstream this year, which will start to see some commercial projects flow into Turkey. Ultimately, that will take gas into Europe, so that's an incredibly strategic and important project certainly for Europe in terms of how that gas will flow and the various pipelines that we have in place and the construction of those pipelines. But Shah Deniz phase 2 this year. That's 99% complete, with an expected startup through the year. We also have Constellation, which is nonoperated, in the Gulf of Mexico where we have a 2/3 working interest. And again, that's expected to start up this year. That's a tieback to one of our other discoveries with our partners there. West Nile Delta this year is another project. We have Taas in Russia; and then of course, Clair Ridge, which is a big North Sea project where we'd expect to see startup this year. So they're all progressing well, a lot of completion. As we've said already, Atoll has come onstream. And all of those things will help overall in terms of production that drives our break-even price down to about $35 to $40 a barrel by 2021 as a function of the surplus cash that we then see. And then in terms of technology, what we're seeing now is there is no question. I mean, well, I'd have said 3 or 4 years ago we were scratching the surface. We're now deep into the surface of technology and what we're learning in terms of productivity and use of people. I think what you're going to see, Thomas, is first of all, we'll continue to keep our focus on costs. We have a strict capital discipline in terms of the $15 billion to $17 billion. And if anything, this year, we're trending towards the lower end of that range, although we've set the range this year of $15 billion to $16 billion. With the first quarter CapEx numbers, it looks like we'll -- certainly we'd set things up at sort of mid part of the range. We're drifting towards the bottom end of that range at the moment. We'll continue to keep a focus on costs, but I think what you're now seeing with the technology is we're getting more productive use of time for the people that we have. And we now have the alternatives to redeploy people within the organization on more productive roles given that they're now getting access to real-time data in any number of different applications not just in the Upstream but in the Downstream and our trading businesses and across the piece. And I just think the whole world of digitization is moving at such a rate of knots, and the cadre of people that we're now hiring is showing us how we can exploit that technology and put it to good purpose and good use that ultimately helps enhance revenues. So yes, there may be more efficiencies to come in terms of our workforces, but it'd be really about how we redeploy people into more productive roles within the company as we use more and more types of technologies that are coming through.

So next question, from Rob West at Redburn.

The oil price is high. As you said, CapEx is coming in below where you'd -- where you're guiding. What I wanted to ask you is how does that change your willingness to flow extra capital into the U.S. shale business and unlock some of the value there. And I noticed the CapEx is slowly going up in the detail you helpfully disclosed, but if you could talk about other plans to add any more rigs in some of the subbasins. And I guess it's a year on from the last time you updated us in detail on that business, but is there any way it was looking particularly attractive to add any incremental rigs and volumes?

So Rob, yes, that's great question. And Lower 48 is the one place where we can ramp up and ramp down. And of course, it's also a function of price. Our break-even economics now are very, very low. In terms of cash breakeven, they are certainly close to $1 for some of the wells that we're looking at, $1 a barrel on a cash break-even basis. We've got 12 operated rigs that we've been running through the first quarter. And actually, we had the team in last week. Dave Lawler and the team were in last week. We were sort of going through that. And then we've got about half of those, just over half of those in the Southern Haynesville, which has been incredibly productive for us. It's a choice. And it's an -- it's something Bernard can do if he chooses to ramp that up. Right now we're still seeing some deflation come through in a couple of numbers, which is why I say we sort of seem to be trending towards the lower end of that $15 billion to $16 billion or that I think somewhere in the midpoint is a good assumption for the year and -- but it's a choice for us in terms of Lower 48. You have to remember we have a very gassy portfolio that we have in Lower 48. It's about 85% gas, 15% liquids. And so it's really opportunity-driven on a point-forward basis, but it is the one place where you can ramp up and ramp down.

That's great. And just to be clear: So with the extra rigs, the Haynesville or some of the more emerging areas in the portfolio...

It's that's a choice for Dave. I can't really sort of pick up the specifics here. Right now I think it's just over 6 or 7 rigs we have in the Southern Haynesville, which has been quite a prospective area for us in terms of some of the things they've been doing with the multi fracs down there. So it's that's where they are at the moment. I don't know what the current plans are for the rest of the year.

We'll take the next question from Michele Della Vigna at Goldman Sachs.

I was wondering if you could give us an update on your LNG strategy. You have clearly been very active with Tangguh and the development [to pre sanction], but also BP has been quite active in contracting new supply and effectively scaling up the marketing efforts. Secondly, I was wondering if you could quantify the economic impact of the expiry of the ADMA license, which has relatively large volumes but pretty small margins.

So on LNG, I think we've laid out before, Bernard has laid out. And it -- and this is integrated with our trading business. So LNG, we see it as an integrated equity and marketing business, but we do have an ambition to expand its portfolio to up to 25 million tonnes per annum. And that's from both a equity perspective and a merchant LNG. As you said, we're taking contracted volumes around the world. And we will continue to move forward on that. We have the Freeport option to export gas out of the United States. That comes up in the time window over the next 18 months in terms of that investment. We have a fleet rejuvenation of our LNG fleet. We'll take that up to, I think we have 6 new vessels, 7. We'll have a total fleet of about 7 LNG vessels going forward. And so we'll continue to ramp that activity up, and I think it gives us a huge amount of opportunity. I think you're going to see quite a number of LNG projects come onto market out to 2022 and if we look at the next big raft of projects. So I'm not sure how much gas will ultimately get exported out of the United States, but we still have a very strong ambition in the LNG space. And in fact, actually we had a good set of results in terms of the first quarter in terms of our gas marketing and LNG activity that you will have seen come through the numbers in the first quarter. In terms of ADMA, I think it's 90,000 barrels a day, which someone's -- or yet, about around 90,000 barrels a day that we'll back out net production as that concession rolls off going forward. And economically wise, it will -- won't have a huge impact in terms of the overall earnings given the nature of that contract, but that will roll off this year.

Okay, we'll take the next question from Chris Kuplent at Bank of America.

Brian, just quick 2 questions. Firstly, I think you didn't fully answer Theepan's earlier question around Brazil. Clearly, Bernard has just been out there, seeing appraisers of pre salt and its attractiveness. And I suppose what Theepan was also asking is how you think you can fund exposure because an MOU, so far, is I suppose fairly cheap but I wonder whether any additional activity together with Petrobras in the pre salt will happen within that $15 billion to $16 billion CapEx range. And secondly, just a quick follow-up on these strong trading results that you've highlighted also in your Upstream division, whether you can give us a little more granularity as far as they are outside of your achieved oil and gas realizations.

Yes. Sorry, Chris. And thank you for reminding me about Theepan's question. Because it did occur to me, answering the question last but one that (inaudible). So we will continue to manage within the $15 billion to $17 billion frame. That's not negotiable. The upper end of that frame is very clear. The lower end of that frame is flexible, depending where the oil price is. Clearly, where oil price is trading at the moment, I think it's unlikely we'll have excursions down to $45 a barrel at the moment, so therefore $15 billion to $17 billion is a good frame going forward. For this year, $15 billion to $16 billion is where we sit. We'll live within that frame. And I think, if you link back, Chris, to the previous comments around where we're seeing deflation and CapEx trending to, we're trending towards the lower end of that range, anyway. And therefore, we'll have up to $2 billion of flexibility within the existing framework, so there's -- I don't think there's anything there that will constrain us going forward in terms of the opportunity set. And of course, every opportunity has to be weighed up against other opportunities that we have in the portfolio set. And I think you're right: Bernard is very strong on the pre salt in terms of Brazil; and we'll see what comes out of that, if there's any potential opportunities for us with Petrobras. But the $15 billion to $17 billion frame is clear, and we'd be very clear about that, to 2021. And then sorry, Chris. Your second question was...

On trading contribution...

Trading contributing, yes. No, I think the way to describe it for this quarter, because we don't give you specific guidance: The oil trading was above average, but it was sort of around a planned type number for this quarter. And on the gas trading it was a strong result, which means it's above average. And that would mean typically $100 million or more over what will be in a typical trading quarter. That came out of North America gas and power. It was as much out of that position and some of the LNG positions that we have, but it was a strong first quarter for them.

Okay, we'll take the next question from Jon Rigby at UBS.

Brian, a couple questions, but first, can we just go back to Whiting and maybe Toledo as well? Was Toledo also affected by (inaudible) of crude flows into it? And then around that, I noticed that the sort of benchmark Midwest refining margins are sort of down, but spreads are up versus sequential earnings in 4Q. So are you able to sort of characterize net-net the contribution from the Midwest refineries sequentially so we can get an idea? Because there's a lot of moving parts. The second question is just on Deepwater Horizon. There's obviously another quarter into the payments, so I just wonder whether you can just offer some observations as you sort of triangulate on final settlements and outcomes et cetera.

Yes, Jon, actually I don't have -- I have not gone into that level of detail around the Midwest, but knowing what I know about the contracts and the way we trade the crude out of indiscernible] and some of the pipelines, I would suspect that Toledo will have been marginally impacted, but the bulk of the impact would have been Whiting. And so that's in the conversations we've had with Tufan. I think the issue has really been curtailment. It has been around Whiting, less so with Toledo given the way in which the pipeline system works coming into Toledo. So Toledo will have been impacted, but I think the majority of the impact would have been Whiting. And in terms of where the spreads are at the moment, I think they're back down in the sort of $15. It -- the spreads opened up off the back of the wedge of production we saw coming in out of Canada. The Canadians are now into -- those positions are now into turnaround, so we're seeing less of that exacerbation. So spreads have moved back into around, I think, $15, $16, which is a good place to be because that's effectively where we set the economics of the Whiting upgrade. So I think $15 is a good place for it to go to settle, but the curtailment issues, we were sourcing some heavy crude at differentials below that minus $15. And -- but of course, we're also capturing the minus $25 on the barrels that we could actually access through Canada. And then in terms of Macondo, we had the big bullet payment, the final payment, to do with the DOJ settlement of 2012, which is $1.2 billion. That's now firmly closed. We -- of the 600 claims that were left inside BEL that led to that higher provision that we had because of the fourth quarter activity, we're now down to I think 299 or 300 claims left to be resolved. There are other claims still being recycled in the system that have been previously denied that will come through the usual appeals process, but I think we have a pretty strong handle now on what that payment schedule looks like. We have everything that was agreed in 2015 with the July '15 settlements. They will start to now kick into action in '19. '18, we had a rest in terms of a -- because of the big payment on DOJ, there was a sort of a pause in '18 on that schedule. That schedule now kicks in next year with the remaining of the BEL piece, where we took the extra provisioning at the end of last year. So I think the numbers for this year of -- are just over $3 billion this year, with $1.6 billion already gone out in the first quarter. Next year, around $2 billion, may actually be -- it'll be around $2 billion. It could be less than $2 billion, but let's say around $2 billion. And then $1 billion a year out to 2032, but I think we're getting a -- more confidence around what that looks like. And the only uncertainty now is left -- 300 claims which are left to resolve through the facility. And we have a process by which we are closing out the balance of those, and as part of that process, payment schedules are being put in place that can go out to 5 to 10 years. So we have some flexibility around how the cash will flow on that front.

We'll take the next question from Irene Himona at Societe Generale.

Brian, 2 questions, please. Firstly, the startup of your 7 major projects last year is what is driving this very strong 14% production growth this quarter. Can you give us a sense of whether the 500,000 BOED plateau of those projects has been reached? Or when during the year it reaches that plateau roughly? And then secondly, obviously your Upstream free cash flow targets are formulated at $55 real. We are now at $75 for the moment. And can you just talk a little bit about what would need to happen perhaps in terms of either the board's thinking or balance sheet gearing for the decision to be taken to step-up the dividend rather than devote the free cash flow to more buybacks?

Yes, Irene, I'll take the second question. And then I'll ask Craig just to sort of follow up on this previous comment around the 400,000 barrels a day and how that looks in terms of plateau. I think we knew this year, with the end of the $3 billion of Macondo payments to go out, that the first focus now -- well, the first priority was to offset the scrip. And so you'll see us do that this year, and you'll start to see the buyback start to ramp back up again having got through that first quarter of those bigger payments around Macondo and the typical seasonal working capital build that you see at this time of the year just like last year. And now as the year progresses, we'll let net debt and gearing come down naturally. And there is no question the board will want to have a conversation. And certainly we talk about it every quarter, the dividend. And so I think we'll be talking more as we go towards the second half of this year. The board will want to go into, well, what will be the conditions that would set up a move on the dividend and how will that look versus buybacks. That will be something for the board to consider. I think, as a backdrop, we'd like to sort of see net debt drift towards the middle of the band, but I mean, frankly, we've got a lot of capacity within that 20% to 30% band. Gearing is at 28% now, which really reflects the working capital build and the Macondo payments in the first quarter, so that will naturally come down. So I think, as that starts to draft down and will -- that's going to be helped by -- somewhat by where the oil price is for now if it stays there, and then I think that will be a "second half of this year" conversation. But we'll pick it up at 2Q results. And undoubtedly, the board will want to have a conversation around that.

Yes, Irene, on the production, the 500,000 barrels a day from those projects. Firstly, that's installed production capacity. Obviously, the projects run at assumed efficiency, operating efficiency. That said, I think, as you go through 2018, certainly by the end of the year, we'll be up at around 500,000 barrels a day as regards to those projects. Okay, we'll take the next question from Martijn Rats, Martijn at Morgan Stanley.

Look, many of my questions have already been answered, but there's one that I was hoping you could still comment on. The 96% and the 86% on plant availability and overall operating efficiency is sort of new disclosure to get very specific numbers on this. So could you give us a bit of a feel for how these numbers have sort of behaved sort of historically? You said that the 86% was 2 points up from the previous all-time high, but when was that, for example? And how did these numbers do year-over-year? And what's the sort of historical band in which they have historically moved? And also, where could you see those numbers still going, going forward?

Yes. So Martijn, thank you. That's a really good question actually. We -- if you'll recall, when we put out our new [SCA] last year, the first quarter of last year, we talked about plant reliability in terms of the 86%. And I think that's 2% higher than the previous high. We also, though, in refining talk about availability, i.e. when -- is the plant available when it was scheduled to be available. We've taken into account turnarounds. And so we put the Upstream on the same basis this year just for consistency in our reporting. So -- but we'll report both numbers. On the reliability measure, we have a long history track record of that. And I think what you're seeing come through that number, the 86%, is the consistency of the projects that have come onstream and how they're performing in that first 6 months when they come onstream but also the focus on the huge number of turnarounds we did in 2011, 2012, 2013. I think it was 48, 35 and somewhere around 27, the following year, of turnarounds of kits focused on safety and ensuring that the integrity of the kit was safe. And of course, where the 2 things now come together is that stronger, safer environment we have leads to better reliability. So we always talk about safety and operational reliability being sort of 2 hands of -- that go together. And the track record basis is that 86% is 2% above the high. And that high, I think, was back in the first quarter of 2015. Previous high was 84%, if I -- yes it was 84% in the first quarter of 2015.

As a brief follow-up: I recognize there is a risk, of course, that you give us one thing and then we always want the next one, but say that 86% goes to, I don't know, 88% or 90% or something along those lines, right, is there a rule of thumb for every 1 or 2 points improvement? Does this impact on costs or earnings? Or is there a way of sort of translating that into a financial number?

That's really hard, Martijn, because it depends on where the production is coming from. If it's coming from a very high revenue cash flow per barrel stream, then obviously that gives you an enhanced -- but I think it would be impossible to come up with a rule of thumb for that because just through -- just by this diversed nature of the cash flows and the regions that we operate in.

Okay, we'll take the next question from Colin Smith at Panmure Gordon.

Two questions. First of all, just on the effective tax rate, it came in quite a bit below the guidance for the year. I just wondered if you could comment why that was. And what happens -- what's the thinking about maintaining the 40%-plus guidance for the balance of the year? And then just on CapEx, I'm curious to see that you've included the extension payments in ACG within the inorganic number given how long you've been involved there. And I wonder if you could just talk a little bit about how you split inorganic versus organic CapEx because obviously things like that do, at the end of the day, represent cash out for investment.

Yes. Maybe on first -- on the second one, Colin, the ACG is -- I think it was over 5 years you'll see those payments coming through. And that was in inorganic. That was the renewal that we did, I think, about 18 months ago. It was the renewal of the ACG license. And so therefore, that was in inorganic. And it's amortized over 5 years, so the payment pops up in each of the 5 years after that. Ultimately that...

I think my point was about why is that considered to be inorganic.

Yes. I'll come back -- yes. Sorry, Colin. I was just going to come to that. And that needs to be managed through the frame that says inorganics and Macondo payments are covered through disposals. And so ultimately it's a reinvestment strategy. And because that was part of a renewal and a license extension, it was treated as inorganic, which just basically comes under the -- our accounting rules of how we treat those investments, but ultimately it has to be paid for through further disposals over time. On effective tax -- is that okay, Colin?

Yes, that's fine.

Okay. Sorry. And then in terms of effective tax rate, it moves around every quarter. It's impossible to pinpoint it based on a single quarter, but based on everything we can say and all the inputs and outputs that we can see, we think above 40% is still good guidance for the year. This quarter, it was down below 40%, driven by deferred tax balances and ForEx movements. And that will happen every quarter, but as we look at the forward schedule of revenues and each of the regions that we're current looking forward to, because of course it's a function of where the revenues and profits arise, we think above 40% is still a good number for the year.

Okay, it's penultimate question from Lucas Herrmann at Deutsche Bank.

Two, if I might. Brian, I just wonder if you could comment on the rate of return which you think you're recycling capital as of the moment. I know the objective is 15% to 20% (inaudible) greenfield, brownfield, but when I look at the projects that you've taken FID on this -- so far this year, the return profile looks -- let's just say it's markedly better than that in certain cases. And the second question was, and apologies for asking this in part, mineral oil tax in Germany. Can you just explain the mechanics in terms of cash flows in and out slightly better? I mean I think our assumption is there's a big payment that takes place in the fourth quarter. One almost expects a reversal in the first quarter of this year, but I'd just like to get a better idea of how one should expect working capital, if that is working capital, to move across Q4 and into Q1.

Yes, so I'll take mineral tax, first, because it's fairly straightforward. It all flows down at the end of the year. This year, for '17, the actual payment was $1.3 billion, flowed out in the fourth quarter. And then over the first 6 weeks of the first quarter of this year, it all flows back in again. And then the first quarter, so you take effectively $1.3 billion, add that to the $1.8 billion; and you'd see the working capital build of maybe just over $3 billion, which will be typical for this year driven by price and volumes that are coming through. But you'll only see the net impacts. Of course, you have that cash flow flowing back in, in the first quarter, but again, that will flow out at the end of this year again. It's typically in the range of $1.2 billion to $1.4 billion, but for 4Q it was $1.3 billion. And then in terms of rate of return, I mean I think you've heard Bernard and Tufan both talk about this. The typical projects we're looking at are mid-teens internal rate of returns significantly above, double-digit percentages above, our cost of capital. And we'll continue to do that, but what you see in the overall returns of our portfolio -- and of course, it's not -- it's a -- we look at the portfolio. We look at strategically where we're looking to grow the company. And we'll make choices about what investments we do and what -- so 4 FIDs so far this year will not necessarily be reflective of the whole portfolio that we're looking at. And typically mid teens, but we're also dealing with the $100 a barrel investments we had over 2010 to '14, and it will take time for that DD&A to work its way through the system before you see us back up above 10% returns for the portfolio and ultimately back into the mid teens for the overall portfolio as we go forward.

Right, we'll take the last question from Christyan Malek at JPMorgan.

I dialed almost slightly a little late, but this may have been addressed but just around just back to the CapEx run rate. Or I just wanted to understand better to what extent is capital efficiency learning curve around new projects coming online. And you sort of talk about your leading-edge focus on technology and digitization. How does that all sort of unlock further deflation at the industrial project break-even level? And could you quantify whether it's a few dollars or possibly more than that, that we're looking for or solving for at sort of the industrial level?

That's a good question, Christyan. And it's really hard to quantify, so a lot of this is anecdotal or qualitative rather than quantitative, but there is no question now. Having established the technology platforms that we initiated 4 or 5 years ago with things like Argus and APEX, there is no question now that we are seeing some benefits of that. And that's why I say CapEx this year we'd set at $15 billion to $16 billion, within our $15 billion to $17 billion frame, but we are undoubtedly moving towards the lower end of that range. And we -- and that's basically coming across the piece in the Upstream in terms of technology and how that's helping us, enabling us to drive deflation -- continue to drive deflation down in terms of the numbers; and we're also seeing now in the Downstream as well, if you look at some of the things that we're deploying in the way of technology there. And I mean I think I said earlier on the very first part of the call that, 4 years, we've been scratching the surface. We're deep into the surface now of technology and digitization. And I think there'll be more to follow on that this year. And I think, at the midpoint -- mid results this year at 2Q, we'll give you a lot more flavor about what we're actually starting to see now from the technology that we've deployed across the piece.

And just to follow up: I mean you sort of -- obviously you had a lower -- it's obviously you had a lower CapEx of $3.5 billion. Are you -- were you surprised of that in terms of efficiencies driving a bit more of a delta; that you're now starting to see that you planned for, let's say, $4 billion for the quarter and this came out at $3.5 billion? I mean, is it right to frame it like that, that you're actually surprising yourself with a downside in terms of structural change but more interactively?

No, no. But I think we're seeing some deflation still come through, but actually 1Q tends to be a low quarter for capital, anyway. So I wouldn't take $3.5 billion and times it by 4 and get to $14 billion. That would probably be the wrong thing to do. 1Q tends to be a lower-capital quarter, but I think, in terms of the Upstream or what Bernard is seeing with his team, there is no question they continue to see some benefits of technology come through in those capital numbers. And like I say, we're going to give you a lot more detail on that as the year progresses.

Okay, very good. That's the end of the questions. I'll hand back to Brian for some final comments. Thank you.

Great. Thanks, Craig.

So thank you for your patience and your time. I hope that the new format has resonated. And we'll take some feedback from you in terms of how that has landed with you in terms of trying to understand the numbers.

I think the way to catch this is we are now 1/4 of the way through the 5-year plan that we laid out for you back in February of last year. We've got 5 quarters under our belt. I think that has built a huge amount of confidence for our team in terms of the trajectory of delivery. We're slightly ahead of where we thought we would be last year, and that momentum has carried on into this year. And there is no question that the safe and reliable operations that underpin everything we do are -- is now starting to flow through in terms of the quarterly results.

So with that, I thank you. And I will look forward to speaking to you at 2Q, where we should have Bob with us on that call.