英國石油 (BP) 2017 Q1 法說會逐字稿

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

I now hand over to Jessica Mitchell, Head of Investor Relations.

Hello, and welcome.

This is BP's First Quarter 2017 Results Webcast and Conference Call.

I'm Jess Mitchell, BP's Head of Investor Relations.

And I'm here with our Chief Financial Officer, Brian Gilvary.

Before we start, I need to draw your attention to our cautionary statement.

During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations.

Actual results and outcomes could differ materially due to factors we note on this slide and in our U.K. and SEC filings.

Please refer to our annual report, stock exchange announcement and SEC filings for more details.

These documents are available on our website.

Thank you.

And now, over to Brian.

Thank you.

Good morning, everyone, and thank you for joining us.

At the end of February, we laid out our investment proposition for the next 5 years and beyond in some detail, so today, I will keep things brief, focusing mainly on our results for the quarter.

It has been a quarter with stronger underlying earnings and robust cash flow, reflecting the firming of the environment relative to prior periods and continued operational momentum in our businesses.

As usual, I'll start with an overview of the environment for the quarter before taking you through the numbers and a reminder of our financial guidance for 2017.

I'll finish up with an update on the progress in our Upstream and Downstream businesses before we take your questions.

Turning to the environment.

Brent crude averaged $54 per barrel in the first quarter, up from $49 per barrel in the fourth quarter of 2016 and $34 per barrel a year ago.

This was despite a brief weakening of oil prices during March following a large and unexpected inventory build in the United States.

Mild weather conditions in the U.S. brought Henry Hub natural gas down from the high in December to average $3.30 per million British thermal units in the first quarter compared to $3 in the fourth quarter and $2.10 a year ago.

The first quarter global refining marker margin averaged $11.70 per barrel compared to $11.40 per barrel in the fourth quarter and $10.50 per barrel a year ago.

Looking ahead, we expect the oil market to continue to rebalance in 2017, driven by above-average global oil demand growth.

The timing and extent of this rebalancing will depend on a number of factors, including, most importantly, whether OPEC cuts are extended into the second half of the year and the extent to which U.S. tight oil responds to the more favorable outlook.

So we expect oil prices to remain uncertain and volatile, but we continue to expect the momentum in our businesses to drive stronger operating cash flows as we move through the second half of the year, driven by our cost restructuring over the last 3 years and a series of new projects we have coming online this year.

Turning now to the results for the group.

BP's first quarter underlying replacement cost profit was $1.5 billion, around $1 billion higher than the same period a year ago and $1.1 billion higher than the fourth quarter of 2016.

Compared to a year ago, the result reflects higher Upstream liquids and gas realizations and higher production, partly offset by higher DD&A and exploration write-offs and the lower contribution from oil supply and trading, although the performance for the quarter remained strong.

Compared to the previous quarter, the result reflects higher Upstream liquids and gas realizations, a stronger contribution from supply and trading and lower Downstream turnaround activity.

First quarter underlying operating cash flow, which excludes Gulf of Mexico oil spill payments, was $4.4 billion.

The first quarter dividend, payable in the second quarter of 2017, remains unchanged at $0.10 per ordinary share.

In Upstream, the underlying first quarter replacement cost profit before interest and tax of $1.4 billion compares with a loss of $750 million a year ago and a profit of $400 million in the fourth quarter of 2016.

Compared to the first quarter of 2016, the result reflects higher liquids and gas realizations and higher production, including the impact of the Abu Dhabi ADCO concession renewal, partly offset by high DD&A and exploration write-offs.

Excluding Rosneft, first quarter reported production versus a year ago was 3% higher.

After adjusting for entitlement and portfolio impacts, underlying production increased by 3% due to ramp-up of major projects.

Compared to the fourth quarter, the result reflects, again, higher liquids and gas realizations and the impact of the Abu Dhabi concession renewal.

Looking ahead, we expect second quarter 2017 reported production to be broadly flat compared to the first quarter, with the continued ramp-up of major projects offset by seasonal turnaround and maintenance activities.

Turning to Downstream.

The first quarter underlying replacement cost profit before interest and tax was $1.7 billion compared with $1.8 billion a year ago and $880 million in the fourth quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $1.2 billion in the first quarter compared with $1.3 billion in the same quarter last year and $420 million in the fourth quarter.

Compared to a year ago, the result reflects improved refining margins and a higher fuels marketing performance, offset by a higher level of turnaround activity and a lower contribution from supply and trading, although, as already noted, the trading performance for the quarter remained strong.

Compared to the fourth quarter, the result reflects a stronger supply and trading performance, a lower level of turnaround activity and benefits from lower costs.

The lubricants business reported an underlying replacement cost profit of $390 million in the first quarter compared with $380 million a year ago and $360 million in the fourth quarter.

The petrochemicals business reported an underlying replacement cost profit of $150 million in the first quarter compared with $110 million a year ago and $100 million in the fourth quarter.

In the second quarter, we expect improved industry refining margins to be offset by both narrower North American heavy crude oil differentials and a higher level of turnaround activity compared with the first quarter.

Turning to Rosneft.

Based on preliminary estimates, we have recognized $100 million as BP's share of Rosneft's underlying net income for the first quarter compared to $66 million a year ago, reflecting a higher Urals price offset by adverse foreign exchange impacts from a stronger ruble.

Our estimates of BP's share of Rosneft's production for the first quarter is 1.1 million barrels of oil equivalent per day, an increase of 11% compared with a year ago and roughly flat compared with the previous quarter.

The increase versus last year reflects the completion of the acquisition of Bashneft, commencement of the Suzun and East-Messoyakha fields and Rosneft's increased stake in the Petromonagas joint venture.

Further details will be available when Rosneft report their first quarter results.

On the 24th of April, the Rosneft board indicated a recommended dividend payout of 35% of IFRS earnings.

At current exchange rates, this would imply a dividend payable to BP of around $200 million after tax for 2016 but is expected to be paid in the third quarter of 2017.

The final decision regarding the payout will be taken at Rosneft's upcoming Annual General Meeting.

In Other business and corporate, the pretax underlying replacement cost charge was $440 million for the first quarter compared with a charge of $180 million in the same period a year ago due to adverse foreign exchange impacts.

We continue to expect the average underlying quarterly charge for the year to be around $350 million, although this may fluctuate between individual quarters.

The adjusted effective tax rate in the first quarter was 33% compared with 18% for the same period last year, mainly reflecting the Abu Dhabi concession renewal.

In the current environment, we continue to expect the effective tax rate to be in the region of 40% in 2017, including the impact of the Abu Dhabi barrels.

Now looking at cash flow.

This slide compares our sources and uses of cash in the first quarter of 2017.

Excluding pretax oil spill-related outgoings, underlying operating cash flow for the quarter was $4.4 billion, including a working capital build of $1.3 billion.

This compared to $3 billion for the same period last year.

Gulf of Mexico oil spill payments were $2.3 billion in the first quarter and included a $740 million Department of Justice settlement payment.

Organic capital expenditure in the first quarter was $3.5 billion compared to $4.5 billion a year ago.

Net debt at the end of the quarter was $38.6 billion.

And gearing was at 28%, within our 20% to 30% target band.

Now, turning to a reminder of our financial frame.

As outlined with our strategy update at the end of February, our framework is based firmly on a principle of disciplined growth.

Having delivered on our capital and cash cost-reduction targets a year ahead of plan, we completed a number of deals at the end of last year to further enhance the growth prospects in the portfolio.

These deals require some additional organic capital expenditure in 2017, but we still expect our overall capital spend for this year to fall comfortably within the $15 billion to $17 billion capital frame we showed you in Baku.

Looking out to 2021, we expect to be able to maintain organic capital expenditure for the group within this $15 billion to $17 billion per annum range while also keeping gearing within our 20% to 30% target band.

At the same time, we will benefit from the startup of our extensive program of Upstream major projects over this period, with 7 project startups planned this year.

We expect the ramp-up of these projects to drive a material improvement in the group's operating cash flow from the second half of the year, along with continued strong underlying performance improvement in the Downstream.

Operating cash flow will also reflect the ongoing focus on continuous efficiency improvement and transformation taking place across the group.

Nonoperating restructuring charges will continue into 2017, although we expect the cash flow impact to be lower than last year.

Looking to inorganic sources and uses of cash.

Deepwater Horizon cash payments in 2017 are expected to be in the range of $4.5 billion to $5.5 billion, with the larger part of the outflow in the first half as we make payments on the annual settlement amounts.

We expect the remaining business economic loss claims to be substantially paid this year.

Total Deepwater Horizon cash payments are then estimated to fall sharply to around $2 billion in 2018 and to step down to a little over $1 billion per annum from 2019 onwards.

Divestments are also expected to be in the range of $4.5 billion to $5.5 billion for this year, with disposal proceeds weighted towards the second half.

From 2018, we expect divestments to reduce to a more typical $2 billion to $3 billion per annum.

Based on our new portfolio, we expect to deliver strong growth in free cash flow out to 2021, as shown on this chart.

This is driven by the underlying momentum in operating cash flow in both our Upstream and Downstream, coupled with our focus on capital discipline across the group.

As noted in February, based on our current planning assumptions, this is consistent with our organic cash balance point reducing steadily to around $35 to $40 per barrel over the period, with the recent portfolio additions adding even more resilience to the portfolio.

Our aim is to ensure that the dividend can be sustained by the underlying cash generation of our businesses over time.

As organic free cash flow grows, we expect our capacity to grow distributions to be materially enhanced.

In the first instance, we would look to address the dilution that arises from the undiscounted scrip dividend alternative we currently have in place.

We would then aim to balance disciplined investment through even stronger growth with our objective of growing distributions to shareholders over the long term.

Now, turning briefly to the highlights for the quarter from our businesses, starting with the Upstream.

As we showed you in February, we expect to add more than 1 million barrels per day of new oil equivalent production by 2021 from 2016, including our recent portfolio additions, with 800,000 barrels per day being delivered from our new major projects by 2020.

The portfolio under construction is ahead of schedule and around 15% under budget.

The first of our 7 planned 2017 startups, Trinidad onshore compression, came online in April.

We expect up to 4 of the 7 projects to be online by midyear.

We have made substantial progress on our other 2017 project startups, as follows: In Egypt, the West Nile Delta project is ahead of schedule; and the Taurus, Libra fields are ramping up.

Quad 204 in the North Sea is in the final stages of commissioning, and we are on track for first oil this month.

In Trinidad, the subsea installation and hook-up campaign for the Juniper facility is now complete.

The project is progressing through commissioning activities, and startup is expected around the middle of this year.

And Khazzan phase 1 in Oman, Persephone off the coast of Western Australia and Zohr in Egypt also remain on track for startup in the second half of this year.

In exploration, we continue to pursue opportunities around our incumbent positions.

For example, in Egypt we made our third gas discovery in the North Damietta Offshore Concession in the East Nile Delta.

We have also commenced the exploration program in our new region of Mauritania and Senegal, an emerging world-class basin.

We will continue to make disciplined capital and portfolio choices within our extensive global hopper of resource prospects, and will continue to exit unattractive positions.

This is an important year of delivery in the Upstream, particularly with the startup of our suite of major projects.

We've made a good start on this and have confidence in delivering the plans we laid out.

You should see the impact of this become increasingly visible as we move through this year and production ramps up.

In the Downstream, we are growing our marketing businesses, delivering strong operational performance and strengthening our competitive position.

Across our marketing businesses, we continued to see year-on-year retail volume growth, and we have added more than 30 convenience partnership sites so far this year.

During the quarter, we opened our first retail site in Mexico, the first international oil company-branded site since deregulation of the fuel retail market in 2013.

Our plans are to expand in this fast-growing market to around 1,500 sites over the next 5 years.

This presents an exciting opportunity not only for BP but also for Mexican consumers.

We also signed an agreement to establish a new retail joint venture in Indonesia, another key growth market for us.

In lubricants, earnings were underpinned by continued strong premium brand and growth markets performance.

Building on our brand strength, we recently announced 2 new partnerships.

We have been appointed the official fuel and lubricants provider to Renault Sport Formula One.

And through our Air BP business, we are now the fuel and carbon-reduction partner of the Red Bull Air Race World Championship.

Turning to manufacturing.

Operations remained strong, with Solomon refining availability for the quarter standing at more than 95%.

And in petrochemicals, we continue to reposition our portfolio to focus on areas where we have leading proprietary technologies and competitive advantage.

In line with this, we recently announced our intention to divest our interest in the SECCO joint venture in China.

While the joint venture has been a successful and profitable investment for us, we believe it has greater long-term value in someone else's portfolio.

The transaction is subject to regulatory approvals.

Also in petrochemicals, we completed the upgrade to our industry-leading proprietary technology at our Cooper River PTA plant this quarter.

This technology will reduce the facility's overall operating cost, making our business more competitive.

In summary, this has been another strong quarter for Downstream.

The business continues to expand earnings potential and improve its competitiveness.

So to summarize.

Earlier this year, we laid out an investment proposition that we believe is good for all seasons and which supports our principal aim of growing sustainable free cash flow and distributions to shareholders over the long term.

This will be delivered, first, through safe, reliable and efficient operations focused on execution across our businesses; second, through continuing to build a portfolio that is fit for the future, one that builds on our strong resource base and positions us to be increasingly competitive in any environment while also ready to make disciplined choices around lower carbon at an informed pace; and third, this proposition will be delivered by maintaining strict discipline within our financial frame and staying focused on delivering returns.

We believe the growth plans we set out for the next 5 years and beyond are well defined.

Our focus over the coming years is firmly on execution of these plans.

You'll start to see this through the ramp-up of our 7 major project startups in the Upstream over the course of this year and in the continued focus on reliability and efficiency in our operations.

In the Downstream, you'll see evidence in continued underlying performance improvement, including the build-out of strong growth options in our marketing businesses.

By the end of this year, you should expect to see the momentum in stronger underlying operating cash flows, which, coupled with our focus on capital discipline, will grow capacity to deliver sustainable and attractive returns to shareholders over time.

So on that note, thank you for listening.

And I'll now open up for questions.

(Operator Instructions)

Welcome again, everybody.

And we'll take a first question from Lydia Rainforth of Barclays.

Are you there, Lydia?

Yes.

Can I come back to the cash flow numbers and just a couple of questions on that?

Brian, there was quite a big working capital build in the quarter.

Can you just talk through what that is?

And when you're talking about a material improvement in cash flow from the second half of the year, can I just check that, that is the $4.4 billion of underlying cash flow from this quarter and do you have a definition of what "material" means?

And then just secondly, just on the CapEx numbers, you're talking about kind of sort of range of $15 billion to $17 billion, where, at the fourth quarter stage, I thought you were talking $16 billion to $17 billion for this year.

Is that just a -- are you more confident about being able to possibly do it towards the lower end of the CapEx range now that you've seen the first quarter results?

Thanks, Lydia.

So in terms of working capital, it's across the piece.

We typically have a working capital build through the first quarter, as we have the product spec changes in the Downstream, so getting the inventories turned around.

Actually, for this quarter, it was about 2/3 Upstream, 1/3 Downstream is where the build was.

And it was across the piece; I mean it wasn't any one specific item.

But it is -- we normally typically get a build through the first quarter.

And actually, it's certainly within the range of historical builds that we've seen in the first quarter, so it's not a big move.

In terms of material cash flows, yes, it is in terms of the operating cash.

It gets driven off the back of the 7 major projects coming on stream this year.

And so the way in which the year was always set up was that the operating cash flow would grow through the first, second, third, fourth quarter, with the major piece coming through in the fourth quarter.

And that's why, if -- by the time we get to the end of the year, you see our break-even economics come down quite significantly.

And by "material," you should assume that number means bigger than a $1 billion delta versus where we are in the first quarter by the time we get to the end of the year.

It will probably be significantly above that, but we'll see how the year pans out and how the projects come on stream, but so far, in terms of where we are with the projects, they're on track, below budget.

We have 1 on stream, 3 more to come on middle of the year.

So I think the operating cash flow for this year has been majorly derisked as those projects have come on and are in the process of ramping up.

In terms of the capital guidance you have in here, actually, we talked about $15 billion to $17 billion at the end of February was the first time that we sort of flagged that up, really to say that actually, having absorbed all of the new projects and acquisitions that we did at the end of last year, by the time we got to the end of February and came out with the investor presentation, I think you'll actually find that we did talk $15 billion to $17 billion there.

We didn't major on it, but it's actually in there.

So it's no change versus that.

And as we continue to optimize the capital within the portfolio, we continue to see further reductions and capacity within the capital frame that, actually, we're comfortable to say we can absorb all of the acquisitions from last year and still manage the capital frame this year in the range of $15 billion to $17 billion.

Thank you.

Next question now from Thomas Adolff of Crédit Suisse.

Brian, Jessica, I've got 3 questions, please, 1 on CapEx, 1 on LNG and 1 on new ventures.

Firstly, on CapEx, if I look at some industry cost indices, let's take the IHS upstream capital costs index, we've kind of come down to around 2006 levels.

And I'm wondering, what is stopping the industry as well as BP to get to the cost levels closer to, say, 2001 or 1997?

I understand reservoirs are a bit more complex, but technologies have also improved.

Secondly, on LNG, your ambition is to get to 25 million tonnes per annum.

Today, you are at around 12 million tonnes per annum.

And you've done some third-party gas deals in Mozambique as well as Freeport as well as a farm-in into Senegal and Mauritania.

And I'm wondering, based on the portfolio you have today, can we get to this 25 million tonne per annum?

Or do you -- are you looking for further third-party gas contracts?

And finally, on new ventures, some of your peers are looking to gain a bigger position in Brazil.

Some already have.

And I wondered what your longer-term ambitions are vis-à-vis Brazil.

Are you interested in doing some bolt-ons, or are you interested to get more via licensing rounds?

Thanks, Thomas.

And that's quite a diverse set of questions.

On capital, 2001, 2002 is an awful long time ago, so I think it's not helpful, given where the industry is today, the nature of the portfolios that we now have today and actually, what's happened in the economics over the last 17 years, over that decade, to try and compare costs back to those sort of levels, as you've had natural inflation come through the economies around the globe.

So in terms of the specifics of trying to rebase things back to 2001, 2002, I don't think that's particularly helpful as a sort of a measure or benchmark.

But if you look at recent history, over the last 4 to 8 years, I think we're now getting back down to sort of levels of costs and capital efficiency that we would have seen before we started to see the oil prices rise through that sort of early part of 2009 and onwards, up to 2014.

In terms of the LNG portfolio, we continue to access supply contracts across the globe.

We still have the intent to get to 25 million tonnes per annum by growing both equity and merchant LNG.

You've already highlighted that we have some new LNG barrels that have come into the portfolio with some of the acquisitions from last year, but I think that goal still remains a realistic goal for us going forward and we'll continue to see third-party supply contracts come in.

Then moving to Brazil: Brazil, you know we entered, back in 2009, with the Devon acquisition.

That is yet to prove successful in terms of what we've found there, but we did acquire licenses at the equatorial margin 3 or 4 years after that.

Today, we currently have 21 blocks in Brazil, of which 4 are BP operated.

6 of those blocks were acquired through the Devon acquisition back in 2011.

And then we also farmed into Petrobras' equatorial position.

We have 8 blocks we've accessed through the ANP round in 2013.

And we also acquired 5 blocks in 2013 through the Petrobras Potiguar Basin.

I think what that says is we have a number of significant positions in Brazil but we've still yet to unlock the potential of Brazil going forward.

Thank you.

Next question now from Rob West of Redburn.

Brian and Jess, I've got 2, please.

One is on the change of production reporting and the way you're treating the technical service contracts in Iraq.

I was hoping you could just talk me through what specifically you've changed and the rationale for that.

I meant to check this before the call, but apologies, I haven't yet.

But does that mean all of '16 and '15 volumes should be restated as well?

And then secondly, on your exploration slide, one thing I noticed that is not on there is the U.K. North Sea.

And I think there are a couple of prospects drilling later in the year which could be quite large potentially.

I think Jock Scott and Craster are 2 of them.

Could you talk a bit about those prospects and where they fit within your exploration plans this year and just give a bit of color around those, please?

Thanks, Rob.

On the first one, it's really just a technical change we've made which effectively affects our oil price movements and lifting imbalances.

It's a very small adjustment and it was made in the first quarter, but it doesn't have any impact on financial results.

I think it will have some marginal changes to volumes, but that's pretty much it.

And then in terms of the U.K. North Sea, we did -- we have actually been awarded 25 blocks in the North Sea on the 29th offshore license round.

And they're round Magnus basin, all of which will be BP operated.

There's 5 blocks there.

On the East Shetland platform, we have 17 blocks across 5 licenses which are all Statoil operated.

And then on Schiehallion North, we've got 3 blocks which will be Shell operated.

But I think the key here is I think it's a good time for the U.K. North Sea.

We have major projects coming on stream, significant investments going into the U.K. And I think things bode well for the North Sea going forward, especially as oil prices have firmed around $50 to $55 a barrel.

Thank you, Rob.

And thanks for sticking to the 2-question etiquette.

We have a long list of callers here.

And we'll turn next to Christyan Malek of JP Morgan.

Two questions.

First, can you provide more details on how you've derisked your startups this year?

And what are the key risks that could not necessarily delay the projects but will result in a lower-than-expected production ramp-up?

I understand it's critical to the operating cash flow, the meaningful move higher that you talk about, so just to understand how you've qualified that risk.

The second question is around CapEx guidance of $15 billion to $17 billion.

What are the things that have to happen to tighten that range over the next 6 to 9 months?

You've potentially surprised the downside of $15 billion.

I'm wondering what are the things that we need to look for, positives and negative surprises, around that guidance?

Okay, Christyan, I think, if I -- Bernard Looney's sat next to me, he would tell you, and he's been saying this now for 3 or 4 years, as has the organization and the transformation we went through in terms of the Upstream organization over the last 4 to 5 years, around all of these projects, I think front-end loading is probably one of the sort of key aspects that's been laid in place that has derisked a number of these projects, which is why they're now tracking significantly below budget at 15%, below original budgets and on track or ahead of time.

And I think it's all the work that's gone into that organization and the way in which that was restructured in terms of how we thought about the organization over the last 4 to 5 years, but I think the front-end loading that's gone into that planning phase of this.

And then I think also, there is also a rhythm and sync in an organization which has projects coming on every 6 or 9 months, getting to a rhythm, rather than an organization where you have a project coming on every 1 or 2 or 3 years and you have to sort of relearn things.

But I think it's about front-end loading.

It's about learning from all of the things that we've done before in terms of project execution, and it's actually at the core of everything.

It's about safe and reliable operations, because that's what drives the operating efficiency once we bring these projects on stream.

What we're seeing differently today than we might have seen 10 years ago was that now when the projects come on stream, we do ramp them up.

They do operate.

And we don't find ourselves having to go back and retro fix things that we may have had to do about 10 years ago.

So I think that organization has come through a very strong learning phase, and that's why I think you're seeing the reliability around how these projects come on stream today.

At least I think that's what Bernard would say.

And then on the capital frame, $15 billion to $17 billion is a good number for this year.

We've set the plans up at round about the middle of that point.

As we bring in some of the projects that we acquired last year, that will require some capital.

Equally, we get more efficient in our deployments, as we've said, that the budgets are only 15% lower on some of these projects for this year.

But it -- we will comfortably live within the $15 billion to $17 billion range this year, and I wouldn't expect to surprise you to the upside or downside.

And just to be clear, that's -- moving from $16 billion to $15 billion, would that be predominantly sort of deflation and efficiency gains, if you could qualify?

It could -- I mean, in the overall days, Christyan, in terms of running the company, it could be project acceleration, slippage.

It could be moving capital around across projects.

It will be further deflation potentially coming through in terms of the numbers, but we manage within that bound.

And actually, within a $2 billion frame, $15 billion to $17 billion, I think that gives us lots of capacity to be able to manage it.

Thank you.

Turning now to Irene Himona of SocGen.

Irene, are you there?

Okay, I'm not picking up Irene...

Can you hear me?

Yes, we can hear you now.

I had 2 questions, please; firstly, one of clarification.

In the first quarter, you paid $2.3 billion on the Gulf of Mexico.

Can you say if that was the same amount pre and post-tax?

In other words, did it -- did the payment attract any tax this quarter?

And then secondly, if you can give us some guidance or a reminder of what your announced acquisition spend is going to be this year, please.

Thanks, Irene.

In terms of Gulf of Mexico, I'm -- I would guess the charge associated with these has already been taken, in that they relate to -- with the exception of business economic loss claims, although the provision was put in place in the middle of last year so that's probably been taken as well.

I would guess most of the tax charge associated with that $2.3 billion has been taken already in previous quarters because there are no new items that have come through.

And so I would not anticipate that, that would have had any effect this quarter.

But we'll come back on that point, Irene, but I'm fairly confident that's the case.

And then in terms of acquisition spend for this year, from memory, the acquisitions that we had last year totaled around, for this year, something close to $500 million to $700 million, is the capital that will go out this year.

And again, Irene, we can come back on the specifics of that, but it's relatively modest amount of CapEx go out this year in terms of those inorganics.

Thanks, Irene.

Next question, from Jason Gammel of Jefferies.

I had 2 questions on the Downstream, if I could, please.

But first, BP is making a pretty concerted effort to build out its retail marketing business.

Brian, I was hoping you could talk about the level of capital that is required to actually build out that business and the level -- the -- how we should think about the returns that, that capital would attract.

And then the second question is related to the petrochemical business, just specific to the divestiture that was made during the quarter.

I generally think of petrochemicals as being relatively high growth, China being a relatively high-growth market.

So can you maybe address the thought process behind the decision to divest that business?

Thanks.

Thank you.

So in terms of the capital frame for Downstream, we run it within a range, and we can go quite low, below this range, but typically, around $2.5 billion to $3 billion per annum is the sort of capital range that we're looking at the moment.

We can go lower than that if we had to, if we found ourselves in a situation where oil prices were low.

But that's a good range going forward.

A chunk of that capital is allocated towards what we'd call license-to-operate or remediation, maintenance and so on capital in terms of the refining business.

And then there's a balance of commercial projects that we look at.

And then the rest of the capital, really anywhere from $800 million to $1 billion, would go in terms of retail and retail marketing, say, something around about $800 million per annum.

And that allows us to invest in a series of growth options for us in terms of the Downstream, particularly around the convenience partnerships that we now have operating across, with Woolworths next year, 6 countries, which have been incredibly successful for us.

And we're expecting another 1,000 new stores across our German network out to 2021 and another 100 new M&S stores.

So I think what Tufan and the team have demonstrated is a very efficient growth investment model for us in the retail fuels business linked with convenience.

And this quarter, we've seen volumes grow by something like over 2% in terms of our retail fuels.

On chemicals, we did announce the sale of SECCO.

And that would have accounted for something like $300 million of contribution from chemicals last year.

So what we have in balance now left in terms of our chemical business is a business where we're targeting double-digit returns over the next couple of years, with demand growth of about 4% to 6% per annum; and having had a series of leading proprietary technologies across PTA, PX and acetic acid.

So I think the core of the business that's left in terms of chemicals has growth prospects of 4% to 6% going forward.

We do have the leading proprietary technologies.

And we are targeting double-digit returns over the next couple of years.

Any comments on the returns of the marketing business, Brian, return on capital employed?

Double digits.

In fact, actually, if I think about the amount of capital we have in refining, the pretax returns of the fuels, what we call the retail marketing business, is probably in excess of 15%.

It's a very attractive business inside the portfolio.

Thanks, Jason.

Next question, from Theepan Jothilingam of Exane.

Brian, Jess, one question, just on gearing.

Brian, I think you've highlighted the target of 20% to 30%.

And it appears the profile for the group sort of rises in H1 before potentially falling back a bit in H2.

But could you just talk about theoretically, if gearing does move to the top end of that range or actually beyond that, is there any material impact in the -- in terms of where the group can operate, any impact on rating or other stakeholders?

Thanks, Theepan.

Actually, the measure we really look at with rating agencies is more about the amount of cash we generate and over the extended debt, which is the sort of sturdy measure that we look at across a suite of measures.

So gearing per se, if it were to track above 30%, that wouldn't cause any concerns in terms of the financial frame, provided we've got the long-term destination point which we've laid out for you at the end of February in terms of the significant sustainable free cash flow growth we've got.

You've already flagged up the issue this year was always set up as the $4.5 billion to $5.5 billion of Deepwater Horizon payments.

The majority of those would go out in the first half of the year.

The disposal proceeds that would cover the costs of those arrive in the second half of the year, so net debt and gearing will track up through the first and second quarter and then drop back down third and fourth quarter.

And, of course, the disposal proceeds have been significantly derisked in terms of cash coming in with the announcement of SECCO last week.

And we now have over $2 billion of announced divestments, with the anticipation that cash will come in as those transactions close this year.

So even if gearing were to track up to 30% or even over 30%, that's not a bust in terms of the financial frame, as the gearing is simply a -- it's a framework.

It's a guidance that we operate to.

The debt, we'd really be looking out 2 or 3 years to look at where that's likely to track.

And as you look at the free cash flows that we talked about at the end of February, you'll see that will naturally decline and come back down towards the bottom end of that range as we see those cash flows come in off the back of the new projects.

So net debt and gearing is not an issue for us at the moment.

Okay.

And then just a point of clarity: On the $1 billion you talked about for Q4 versus Q1 underlying, is that on the $4.4 billion with the working cap, or without the working cap?

Yes, Theepan, just to be clear, I'd -- I've -- hopefully, what I said was the number that we use as material -- Lydia's question was how do you define "material," $1 billion is what we would call "material." 4Q versus 1Q, I would expect to be certainly above that number on a flat oil price basis, but it will be materially -- the question she asked was, well, how do you define the second half of the year being material versus the first half.

And just simply $1 billion is what we use as a materiality threshold.

But in terms of operating cash, it will be significantly above the $1 billion by the time you get to the end of the year.

Yes, but is that on the $4.4 billion?

Correct, versus of -- that $4.4 billion operating cash, yes.

But actually, Theepan, it's sort of -- it's logical, if you think about the projects coming on stream and ramping up in the second half of the year, that the operating cash flow will be heavily weighted towards the second half of the year versus the first half.

Thank you.

Moving now to Jon Rigby of UBS.

Jess, Brian, 2 sort of biggy questions, I'm afraid.

The first is just to go back on the Macondo outflows.

I think it's right that the pre- and post-tax numbers are the same in terms of cash.

And so with sort of a big tax receivable that's been built up, I'm just trying to understand when you start to be able to recoup that.

Is it reliant on the U.S. business, Upstream business returning to profit?

And I know it actually did this quarter, but is that the main driver of recouping tax?

Or can you go back and access historic profits?

That was my first question.

The second, when you made the announcement on SECCO, it struck me or it surprised me just how big a component part of your petrochemicals business profitability SECCO was.

Are you able to give me some kind of indication of its contribution to the first quarter chemicals number, which is obviously an improvement of historic levels we've seen?

I'll come back to that second one, Jon.

We wouldn't normally give you a specific asset contribution for the first quarter.

On chemicals, what I would say is that the -- so first of all, the price that was announced last week was based on a very high earnings number, so it was the sort of top of the cycle.

If you look at it on a through-cycle basis, the actual multiple we got was closer -- was actually probably above 7x in terms of multiples.

The number that was out there for last year of $400 million was a post-tax number, which is equity accounted, and therefore, through the results we saw last year, you'd actually need to take $100 million off that.

So the actual number would be $300 million post-tax, which was what we -- was reported last year in the Downstream segment for SECCO.

So there was underlying profit from the rest of the chemicals segment.

We wouldn't normally give you the SECCO number for the first quarter.

I'd just reiterate what I said earlier about the prospects of the remaining assets within the chemicals portfolio, with 4% to 6% growth prospects; the proprietary technology that we have in place around PTA, PX and acetic acid; and the target to get that to double-digit returns over the next couple of years.

On the tax, on the recouping of tax, we have been recouping tax in terms of the credit that we'd built up from 2010 to date.

And we are recuperating that tax today.

I think if I went back and looked at the forward profile in terms of Macondo, I think we'll end up being back in a tax-paying position in the U.S. over the next 1 to 2 years.

Thanks, Jon.

We'll take a question now from Alastair Syme of Citi.

Jess, Brian, can I just ask on just one question on you're driving down the cash balancing point to $35 to $40 by 2021.

And I'd note you're not the only ones in the industry reducing costs aggressively.

And then I look back at the annual report.

You're still using $75 real from '21 for your fair value analysis, so almost twice that balancing point.

Can you just help us square the circle on those 2 numbers, how you think about that?

Yes.

The cash -- so actually, the numbers we laid out for you in terms of the $35 to $40 was at $55 a barrel real going forward.

That was for basically laying out the growth prospects of the company at what effectively is today's prices, if you sort of look at where we're averaging at the moment.

At least back at the end of February, that's where we were.

So that's why we laid out the targets in the way that we did, and a lot of that is not so much driven by costs.

It's driven by revenues in terms of the new projects coming on stream, the underlying performance improvement that Tufan talked about in terms of Downstream, growing those retail markets actually with some growth in chemicals as well over the piece.

So it was really more revenue-growth driven.

It was a very growth-driven strategy, maintaining costs where they are today and getting more efficient in our use of costs on an industry basis as we bring on new costs and new projects.

So that was a sort of background to that.

In terms of the impairment tests, we've used our -- we use a number of prices that we look at.

$75 a barrel is a long-run number out 2021 and beyond that we use for projects, but we also run those projects at $50 a barrel.

So today, we have a $50 a barrel case and a $75 a barrel case.

And the $75 is simply consistent with what we've used beyond 2021 for impairment testing.

That's -- the $75 is still the long-term planning assumption of the company?

Is that right?

Is that...

It is one of the -- it is the long-term planning assumption beyond 2021.

That gets reviewed every year.

And then all of our projects that we currently commission and FID at the moment are tested then at $50 a barrel.

Okay, moving now to Martijn Rats of Morgan Stanley.

I have no further questions.

All my questions have been answered.

That's good to hear, Martijn.

Thank you.

We'll then go to Anish Kapadia of TPH.

Yes, a couple of questions, please.

First of all, I was wondering if you could talk about reducing your discount rate for impairment testing.

I think that's gone to 6% now from 8% a few years ago.

And how does that factor into your required rate of return when you're thinking about sanctioning projects and acquisitions?

That's the first question.

The second one is on kind of looking at your cash flow versus earnings.

If I look back at 2016, according to the annual report, I think last year, you exceeded your operating cash flow target by 5%, but you missed your earnings target for last year by 10%.

So I was wondering if you could explain that difference and, in terms of 2017, talk about the impacts that we should expect in terms of cash tax versus P&L tax and any kind of other cash impacts such as provisions and pensions on the cash flow.

So the simple answer which -- in terms of operating cash versus earnings would have been DD&A and exploration write-offs.

You actually go and look at what happened through the year.

I suspect that DD&A was running slightly higher.

And we -- certainly, we've had higher exploration write-offs than we would have anticipated.

And, of course, both of those are noncash items.

So that would normally be the source of what the difference is between the two.

In terms of discount rates, actually it went from 7% pre Macondo to 8% for a period of time and then was reassessed down at 6%.

In terms of long-term investments, we still expect to be in the sort of double-digit teens in terms of IRRs are projects we expect, in some cases, at the very high end.

And it's all a nature of whether the project is a -- the nature of what that project is, whether it be long term and strategic where -- or, say, an infill development round an existing field or the sort of retail marketing investments that we were talking about before which could -- would be at the high end of returns.

There may be some lower-end-teen ones that we'd look at, but that would -- really from a portfolio effect, we're looking for a portfolio of options from a risk perspective that give us a range of outcomes in terms of IRRs.

The ultimate measure will be actually, which you will also see in the annual report and accounts, ROACE has reappeared as a long-term metric, which is really about how we now rebuild the company having come to this period of high oil prices, the correction down to low oil prices and now how we work that capital going forward.

And it all comes back to this $15 billion to $17 billion frame, getting more efficient in our use of capital and driving returns but making sure that we might make the right choices as to how we do that.

And anything on the cash impacts for 2017 that we should bear in mind?

What sort of cash -- I'm sorry, Anish.

What sort of cash impacts were you thinking for 2017?

Oh, it's versus '16?

Yes, so it was -- the main -- so well, the main things I was thinking was in terms of the cash flow, anything significant in terms of cash tax versus P&L tax; and then provisions, pensions; and anything on those to kind of bear in mind this year.

No, not from a cash perspective.

I think all the guidance we gave you at the start of the year is probably still good in terms of those requirements.

Things can still move around, round tax legislation, but cash tax rate is still running relatively about 8 percentage points below where the effective underlying tax rate is.

But you'll start -- you'll continue to see that effect going forward.

Thank you.

Turning now to Biraj Borkhataria of RBC.

A couple on the U.S. onshore business.

Could you just talk about your activity levels at the moment and what your plans are for the course of this year?

It looks like your capital budget continues to trend lower, which is positive.

At the same time, your production costs appear to have stabilized over the last few quarters, so I was wondering if you're seeing any signs of cost inflation in the U.S. onshore business.

And then secondly, just a quick clarification on Zohr, the acquisition.

Is that effectively paid now?

I know there was an element of reimbursing past CapEx.

Is that phased through the year, or is that all done in Q1?

Thanks.

In terms of U.S. onshore, we today have -- I think we're now back up to about 12 rigs in the first quarter of '17 versus 5 in the fourth quarter.

You'll see that ramp up as the team experiments within each of the basins, but we're now running 12 rigs.

Cash breakeven on a full free cash basis has now come down, almost halved from the full year '15 to where we are in the first quarter of '17, down around $2.60 or that sort of level in terms of cash breakeven.

Not seeing any inflation at this point in terms of Lower 48, although you can see, in terms of Lower 48, last time I looked, I think the total rigs back in action were about 660, 670 versus the peak of about 1,680, I think.

So it's still way, way off where the peak was, but there's certainly more activity coming through.

But we're not seeing a huge amount in the way of inflation.

We're continuing to reduce operating costs and improve on our capital efficiency.

And 2017 is really a development program that pivots on the focus on robust projects and growth and trying to take out any underperformance that we see in the activities.

And we're continuing to target the resource base to make sure that it's economic, below $3 Henry Hub, on an earnings basis.

And as I say, on a cash basis, it's below that.

So Biraj, that was the U.S. onshore.

Was the -- what was the second question?

Second question was on Zohr.

Has that effectively been paid for now as of Q1, or is there some reimbursement of past CapEx to come through later?

No, the CapEx has been taken care of, but we don't talk about the actual cash that we've outlaid for Zohr in terms of the commercial deals that we actually agreed with Eni.

So we wouldn't normally give you any specifics on that.

Thanks, Biraj.

Now to Chris Kuplent of Bank of America.

Just 2 quick ones, follow-up, I think, to what Irene asked about 2017, Brian.

What kind of inorganic CapEx have you already got visibility on for 2018?

With Woolworths and some follow-ups, I guess we're looking at $1.5 billion.

Would that be a decent number?

And on Q1, just a quick catch-up: If you look at Rosneft and the other segments, would it be fair to say that FX has contributed to about $200 million there or thereabouts in terms of, well, extra costs?

Yes, it's not so much extra costs, Chris.

It's just simply a ForEx transaction effect and it is just over $200 million, so you're right.

That's the right sort of order of magnitude across the 2 pieces.

In terms of inorganics, no, the inorganics are mostly done.

The only thing that's left to come through is really Woolworths next year, which we will self-fund with our disposal activity that we have set up for next year.

If you remember, we said disposals, around $2 billion to $3 billion per annum.

Next year, Macondo payments are closer to $2 billion and then ramping down to $1 billion.

So we will manage the Woolworths acquisition through self-funding within the company in terms of other potential disposals that we have slated.

So that won't see a bump in terms of draw on cash for 2018.

Okay, so the $1.3 billion Woolworths is not included in your $15 billion to $17 billion, yes?

Correct.

That will be inorganic capital that will be funded through disposals.

Thanks, Chris.

Now to Brendan Warn of BMO.

Just, I guess, a follow-up on CapEx and your comments you made on your expectations of rebalancing it before the end of this year.

And I guess that was caveated by obviously an extension of the OPEC cut.

Can you just talk about that, call it the, floor on your organic CapEx expenditure range from 2018?

Just, call it, how low could your $15 billion go before you actually start cutting into the bone?

And then also, on the flipside, I think I remember you referred to $17 billion being a hard ceiling, but could there be any pressures on that in the next couple of years?

Yes, Brendan, you've -- actually, I think you've answered your own question.

$17 billion is a hard ceiling.

$15 billion is not a floor.

If we saw a period where oil -- you have to remember that there -- so in terms of oil price, we have a number of factors.

OPEC rolling its cuts is one factor.

Demand is another.

And by the time we get out to 2018, if you see growth this year and demand of about 1.4 million barrels a day, something similar or even less next year, things will naturally start to come back into balance.

But in the event that they didn't, for whatever reasons, and oil price remained under pressures, back below $50, say, down at $45, $40, then we can certainly take the capital lower.

And then we'll get -- but...

What sort of level, Brian?

Well, we're not going to give you a level, Brendan, in terms of what that number looks like, but we could certainly take another $1 billion out if we had to, though, in that scenario.

But all options are open to us at that point in terms of flexibility within the financial frame, what else we'd need to look at.

But I think it's an unlikely scenario from where we are today.

As you see demand grow, we expect crude stocks to come back into line.

Actually, crude stocks will probably still be at the top end of their historic range by the end of this year.

So I think something around $50, $55 a barrel seems a reasonable assumption on a point-forward basis.

If it drops below $50, we have further flexibility in terms of how we manage that.

Thanks, Brendan.

And now we'll take our last question from Lucas Herrmann.

And if you make it quick and easy, Lucas, we might get this call done in an hour.

Jess, I'll try.

Brian, Macondo, just an update in term -- the question on Macondo is very simply where are we in terms of outstanding claims?

Guidance, $4.5 billion to $5.5 billion for the year after $2.3 billion in the first is pretty encouraging in terms of the decline one's going to see.

And second quick question, how much CapEx -- or sorry, how much cap em is there in the chemicals business post the sale of SECCO, broadly $3 billion, $3.5 billion?

Capital employed?

Yes.

I'll come back to that because it's not something I've looked at recently.

Claims, we're down to about -- in terms of business economic loss claims, which is the sort of thing that was moving around most, of the 149,000, we're down to about 4,000, of which 3,000 are recycled claims that at one point although had been rejected and have come back into the system through the process that's allowed.

So I think we're down to less than 1,000 claims now in terms of closing that process out going forward, in terms of less than 1,000 claims that we haven't yet had line of sight of.

So I think we're now finally into the tail around business economic loss claims and in terms of Macondo, and therefore, being able to quantify and price up what that looks like on a quarterly basis, we're much closer to now.

In terms of the capital that's left inside chemicals, I'm guessing it's got to be somewhere around $3 billion, but I honestly -- Lucas, firstly, I'm surprised you're the last question.

You were never going to make that 30 seconds that Jess gave you to get that question in, but we'll have to come back to you on what's left in chemicals.

But I'm guessing something around $3 billion.

Thanks, Lucas, and thank you, everybody.

Great.

So just to conclude, thanks for your time.

Appreciate that you've taken up, surprisingly, an hour to finish the call.

It's probably a record for us.

Just to reiterate, I think this has been a good quarter, robust earnings and cash flow.

We continue to see strong operating performance in both Upstream and Downstream, and that's a real key for us in terms of going forward.

The projects are on track and below budget.

And we're seeing Downstream marketing growth come through this quarter.

But just to put all of this in context: It is simply 1 quarter in the 20 quarters that we laid out for you back at the end of February, but nevertheless, a very good, strong start.

And the company will, of course, continue to focus on safe and reliable operations because that will actually help drive growth over the next 5 years.

So with that, thank you very much for your time.