英國石油 (BP) 2017 Q3 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 Third 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.

Thanks, Jess.

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

Our third quarter results saw continued strong operational and financial performance.

The Upstream and Downstream businesses are executing against the growth plans we laid out at the start of the year, and we have seen another quarter of robust underlying earnings and cash flow delivery.

All of this provides us with momentum as we approach the end of the year and look forward into 2018.

I'll start by looking at the external environments in more detail before taking you through the results and updating you on the financial frame, including the significant progress made in rebalancing sources and uses of cash.

I'll then finish with an update on progress in each of the segments before taking time to answer any questions.

So starting with the oil market.

The Brent oil price has shown some recovery since September, reaching the highest level since July 2015.

Inventory reductions and continued efforts from OPEC to maintain cuts supported price gains in the third quarter.

Looking ahead, there are a number of factors influencing the oil price.

Oil demand over the remainder of the year is expected to remain robust.

Non-OPEC supply is projected to increase, largely driven by stronger U.S. tight oil production.

At the same time, overall compliance among the OPEC and non-OPEC countries participating in agreed production cuts remains high, and the agreement is currently in-force through March 2018.

Overall, we expect inventory levels to continue to edge lower, although there still remains a lot of uncertainty around the pace of that adjustment and around the longer-term outlook.

Turning to the environment in the quarter.

Brent crude averaged $52 per barrel in the third quarter compared to $50 a barrel in the second quarter of 2017 and $46 per barrel a year ago.

Henry Hub gas prices averaged $3 per million British thermal units in the third quarter compared to $3.20 in the second quarter and $2.80 a year ago.

BP's global refining marker margin increased above seasonal norms, primarily due to Gulf Coast refining outages as a result of Hurricane Harvey.

The third quarter averaged $16.30 per barrel compared to $13.80 per barrel in the second quarter and $11.60 per barrel last year.

Looking at the results for the group.

BP's third quarter underlying replacement cost profit was $1.9 billion compared with $930 million a year ago and $680 million in the second quarter of 2017.

Compared to a year ago, the result reflects higher liquids and gas realizations, coupled with higher Upstream volumes from major project start-ups and the Abu Dhabi concession renewal and underlying Downstream growth and a strong refining environment, partly offset by the absence of a one-off tax benefit related to the U.K. North Sea.

Compared to the previous quarter, the result reflects higher liquids realizations, lower exploration write-offs and the stronger refining environment, along with an improved oil supply and trading result after a weak second quarter.

Third quarter underlying operating cash flow, which excludes pretax Gulf of Mexico oil spill payments, was $6.6 billion.

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

In Upstream, the underlying third quarter replacement cost profit before interest and tax of $1.6 billion compares with a loss of $220 million a year ago and a profit of $710 million in the second quarter of 2017.

Compared to the third quarter of 2016, the result reflects higher liquids and gas realizations, along with higher production, including the impact of the Abu Dhabi concession renewal and major project start-ups and lower exploration write-offs, partly offset by higher DD&A.

Total production for the group was 3.6 million barrels of oil equivalent per day for the quarter.

Excluding Rosneft, third quarter reported production was 2.5 million barrels per day, 16% higher than a year ago.

After adjusting for entitlement and portfolio impacts, underlying production increased by 11%, due to the ramp-up of major projects.

Compared to the second quarter, the result reflects lower exploration write-offs and higher liquids realizations.

Looking ahead, we expect fourth quarter reported production to be higher than the third quarter, reflecting the continued growth from major projects and recovery from the seasonal turnaround and maintenance activities.

Turning to Downstream.

The third quarter underlying replacement cost profit before interest and tax was $2.3 billion compared with $1.4 billion a year ago and $1.4 billion in the second quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $1.8 billion in the third quarter compared with $980 million a year ago and $910 million in the second quarter.

Compared to a year ago, the result reflects strong refining operational performance capturing improved industry refining margins, partly offset by narrower North American heavy crude oil differentials, continued earnings growth in fuels marketing and an improved supply and trading contribution.

Compared to the second quarter, the result reflects increased refining performance from stronger operations, higher industry refining margins and a lower level of turnaround activity, a stronger supply in trading contribution after a weak second quarter and continued earnings growth in fuels marketing.

The lubricants business reported an underlying replacement cost profit of $360 million in the third quarter reflecting continued premium brand growth, offset by the impact of higher base oil prices due to temporary supply constraints.

And the petrochemicals business reported an underlying replacement cost profit of $190 million in the third quarter, reflecting an improved margin environment, improved margin optimization and lower costs from our simplification and efficiency programs.

While industry refining margins have remained robust coming into the fourth quarter, we would expect a normal seasonal decline compared with the third quarter, and we expect a higher level of turnaround activity in the fourth quarter.

Turning to Rosneft.

Based on preliminary estimates, we have recognized $140 million as BP's share of Rosneft's underlying net income for the third quarter compared to $120 million a year ago and $280 million in the second quarter of 2017.

The estimate reflects a high Urals price and duty lag benefit but was impacted by adverse foreign exchange movements.

Our estimates of BP's share of Rosneft's production for the third quarter is 1.1 million barrels of oil equivalent per day, an increase of 9% compared with a year ago and broadly flat compared with the previous quarter.

The increase compared with last year reflects the completion of recent acquisitions and new fields coming online.

In line with the new dividend policy that includes payments to shareholders twice a year, Rosneft announced an interim dividend for the first half of 2017 representing 50% of IFRS net income.

At current exchange rates, BP's share of the dividend is around $120 million after tax and is expected to be received in the fourth quarter.

This is in addition to the $190 million received in the third quarter for the 2016 annual dividend.

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

In other business and corporate, we reported a pretax underlying replacement cost charge of $400 million for the third quarter.

The average quarterly charge for the first 9 months of the year is $400 million.

The adjusted effective tax rate for the third quarter was 40% compared to 37% a year ago.

This reflects the impact of the Abu Dhabi concession renewal and other changes in the mix of profits.

We expect the full year underlying effective tax rate to be above 40%.

Moving to cash flows.

This slide compares our sources and uses of cash in the first 9 months of 2016 and 2017.

Excluding pretax oil spill-related outgoings, underlying operating cash flow was $17.9 billion for the first 9 months, of which $6.6 billion was generated in the third quarter.

This includes a working capital release of $1.5 billion in the first 9 months, with $1.4 billion in the third quarter.

Organic capital expenditure was $11.9 billion in the first 9 months and $4 billion in the third quarter.

Divestment proceeds year-to-date totaled $1 billion.

Pretax Gulf of Mexico oil spill payments was significantly lower in the third quarter at $560 million, bringing payments for the first 9 months to $4.9 billion.

Net debt at the end of the quarter was flat compared with last quarter at $39.8 billion.

Gearing reduced to 28.4%, within our 20% to 30% band.

Turning to the financial frame.

We've made strong progress in rebalancing organic sources and uses of cash.

Underlying operating cash flow more than covered organic capital expenditure and the full dividend in the quarter where Brent averaged $52 per barrel.

We remain confident in sustaining a balanced position in 2018 and beyond, which will allow us to begin offsetting the dilution from our optional scrip dividend.

I will come back to the detail of this shortly.

Our operating businesses continue to execute against the plan we laid out at the start of this year.

Upstream have now started up 6 of the 7 major projects planned for the year and Downstream continued to deliver resilient underlying performance across the businesses.

Across the group, we remain focused on delivering continuous efficiency improvements as we progress our modernization and transformation agenda.

Our capital expenditure plans remain very disciplined.

Looking out to 2021, we expect to maintain organic capital expenditure within a range of $15 billion to $17 billion without exceeding $17 billion in any year.

We expect organic capital expenditure this year to be around $16 billion.

For 2018, at oil prices of around $50 per barrel, we would expect to be at the lower end of the range.

However, as we have said previously, this is not a floor.

If oil prices move structurally lower, we will continue to drive towards an even lower investment frame for the group.

Turning to inorganic cash flow.

In line with our previous guidance, we expect the full year Gulf of Mexico oil spill payments to be around $5.5 billion.

From 2018, we expect payments to be materially lower at just over $2 billion, weighted towards the first half of the year, consistent with the civil and criminal settlement schedule.

Payments then stepped down to a little over $1 billion per annum from 2019 onwards.

Divestment proceeds expected to be received in the fourth quarter include $1.4 billion from the SECCO transaction announced in the second quarter and net proceeds of over $700 million from the initial public offering of BP Midstream Partners.

Total proceeds in 2017 are expected to be around $4.5 billion.

Longer term, we expect divestments to reduce to a more typical $2 billion to $3 billion per annum, while remaining a lever for high grading our portfolio and creating flexibility within the financial frame.

Now coming back to the oil price balance point.

As already noted, we delivered surplus organic free cash flow of $1.8 billion in the first 9 months.

The Brent oil price cash balance point for the group was $42 per barrel or the equivalent of $49 per barrel on a full dividend basis.

Our balance sheet remains robust with gearing at 28.4% at the end of the third quarter, down 0.4% from the end of last quarter and within our target 20% to 30% band.

With that background, let me remind you of our position on the scrip dividend option that we provide to our shareholders.

This program was put in place in 2010 as an undiscounted alternative to the cash dividend.

On average, since inception, the election uptake has been around 20%.

This has provided some financial flexibility during the transition to lower oil prices.

We have also been clear that once we return to generating free cash flow, our intent would be to address the dilution from the scrip dividend as a first priority.

Given the strong progress we have made towards rebalancing so far this year and our confidence in our ability to grow organic free cash flow in 2018 and beyond, we will be recommencing a share buyback program this quarter to offset the impact of the second quarter scrip dividend issued in September.

Looking ahead, our intent would be to offset any ongoing scrip dilution through further buybacks over time.

The shape of the program will not necessarily match the dilution on a quarterly basis but will reflect the ongoing judgment of factors, including changes in the environment, the underlying performance of the business, the outlook for the group financial framework and other market factors which may vary from quarter-to-quarter.

Looking further out to 2021 and in a constant price environment, we expect organic free cash flow to grow, driven by the growth in our Upstream and Downstream businesses with the organic cash balance point for the group reducing steadily to around $35 to $40 per barrel covering the full dividend, including scrip.

With free cash flow growing, we will then aim to ensure the right balance between disciplined investment and distributions growth, depending on the context and outlook at the time.

Now turning to milestones and progress across our businesses.

In the Upstream, our track record of delivery of new major projects continued in the third quarter.

We now have 6 out of our 7 2017 major projects online.

Along with our first half start-ups in Egypt, Trinidad and the U.K. North Sea, we have brought online 3 more projects, each of which started up on or ahead of schedule and under budget.

In July, Persephone in Western Australia started up successfully and is expected to produce around 50,000 barrels of oil equivalent per day gross from 2 wells tied back to the existing North Rankin complex.

In August, Juniper, BP's first subsea field development in Trinidad, came online.

It is the largest new project to start up in Trinidad for several years and is expected to produce around 95,000 barrels of oil equivalent per day.

In September, we began production from the giant Khazzan gas field in Oman, BP's largest 2017 start-up.

We expect the first phase of the project, made up of 200 wells feeding into a 2-train central processing facility, to deliver 1 billion cubic feet per day gross.

Production will gradually ramp up through a single 500 million cubic feet per day train with a second identical train expected to come online in the next few months.

Production is expected to rise to 1.5 billion cubic feet per day with further expansion of the project, which is on track for 2020.

The 2 phases together will develop an estimated 10.5 trillion cubic feet of recoverable gas resources.

Zohr in Egypt remains on track to come online this year to complete the 7 major project start-ups we planned for the year.

Aided by these major projects brought online in 2017, year-to-date underlying production was around 7% higher than a year ago.

In September, BP, together with our partners, extended the production-sharing agreement for the Azeri, Chirag and Deepwater Gunashli fields in Azerbaijan to the end of 2049.

This renewal, which extends the PSA by 25 years, includes changes to the partner equity shares alongside improved profit share terms.

Through the extension, we have also accessed more than 200 million barrels of proved and probable reserves at $5 to $6 per barrel.

We see enormous potential to optimize around this giant field and the renewed agreement allows us to progress into the next stage of development of a new platform project.

And also last week, Aker BP, in which we hold a 30% stake, entered into an agreement to acquire Hess Norge.

Through this transaction, Aker BP becomes the sole owner of the Valhall and Hod fields in Norway.

We see great future value here through increased oil recovery and flank developments.

This demonstrates the ambition of Aker BP to continue to grow, and we expect to see the benefits from late 2017 through increased dividends.

And as part of the recent third Pre-Salt Bid Round in Brazil, we've secured 2 licenses in partnership with Petrobras and CNPC.

These exploration blocks presents us with the opportunity to test some of the largest oil structures in the prolific Santos pre-salt basin.

Our strong performance year-to-date in the Upstream underlines our progress, and we see this momentum continuing as we look to 2018 and beyond.

In Downstream, we continue to make good strategic progress, delivering underlying earnings growth in both our marketing and manufacturing businesses, delivering the highest quarter for underlying earnings in 5 years.

In fuels marketing year-to-date, we've delivered double-digit earnings growth and grown premium fuel volumes by 7%.

We continued the rollout of our convenience partnership model to more than 170 retail sites.

This brings our total number of convenience partnership sites to over 1,000 globally.

In addition, we have continued to build our strategic partnerships, which are underpinned by the strength of our brands.

For example, in lubricants, we announced the renewal of our global partnership and supply agreement with Volvo.

As previously mentioned, the initial public offering of BP Midstream Partners in the U.S. delivers net proceeds of over $700 million.

In refining, we continued to grow the value from commercial optimization across the portfolio.

In the U.S., Solomon availability for the quarter was the highest in more than 10 years, and we processed record levels of advantaged feedstock.

And in petrochemicals, we expect to complete the sale of our share in the SECCO joint venture in China in the fourth quarter.

So in summary, we have made solid progress year-to-date in delivering against the key milestones we set for ourselves and have established strong momentum in the longer-term investment proposition that we laid out earlier in the year.

We are building a track record of organic growth across both our key businesses.

The tangible progress we continue to see in sustainably rebalancing organic sources and uses of cash will allow us to recommence a share buyback program to offset the dilution impact of the scrip dividend later this quarter.

In the Upstream, we have started up 6 of the 7 major projects planned for the year, in many cases ahead of schedule and under budget.

In the Downstream, we have added more than 170 new convenience partnership sites, underpinning the growth proposition across our marketing businesses.

We continue to optimize our portfolio and seek further opportunities to support renewal and growth in the future.

We remain committed to capital discipline and continue to focus on driving costs lower in a safe and sustainable way.

Taken together, these support our principal aim of growing sustainable free cash flow and distributions to shareholders in both the near and long term.

So on that note, thank you for listening, and we'll now open up to questions.

(Operator Instructions)

Thank you, everybody, for joining the Q&A.

As many of you will know, it's my last call today for BP, and so I'm hoping we'll keep it very efficient.

(Operator Instructions) We'll take the first question from Oswald Clint of Bernstein.

Go ahead, Oswald.

Jess, congratulations, and thank you for all your help over the years.

Yes, Brian, 2 questions, please.

Firstly, on the buyback, it's obviously clearly signaling confidence in that cash flow stepping up in 2018 and beyond.

But so in that context, I was wondering if I could potentially tease out of you some kind of Upstream cash flow growth numbers for 2018.

For example, if I look at the new project start-ups at a similar oil price to what we've had this year, I'd be coming close to another $3 billion worth of cash flow in 2018.

I just want to sense or check if that's massively off side.

And then second question was really on the Lower 48 business.

When I look at the OpEx per barrel you've reported, it's at the lowest level since you started splitting out this business.

So is -- with the inflationary pressures inside the Lower 48, is that kind of the end of the runway there with the OpEx per barrel for the Lower 48 business?

Thanks, Oswald.

So on the first piece, we wouldn't normally subdivide out in a particular year, Upstream, Downstream or the Other businesses in corporate in terms of cash flows.

What I'd say is we're on track in terms of $13 billion to $14 billion of free cash pretax proxy that we laid out, that Bernard and his team laid out for you at the start of this year.

So we're on track in terms of what we expect it to be.

If anything, we're slightly ahead of where we have anticipated to be this year, hence, why the announcement we have around buybacks and getting things back to neutrality.

As you look at where we started from in terms of 2014, the rebuilding of the company out to 2017, where we are today, you will see the ramp-up of those projects that you saw this year start to come through next year, and therefore, you will start to see significant free cash flow.

I think a good proxy for it is if you look at the EBITDA numbers, which you should be able to derive from the stock exchange announcement for each of the 2 segments.

And indeed, you will start to see the ramp-up certainly this year in terms of the Upstream getting back into position of growth and similarly with Downstream.

So I can't give you any more specificity in terms of next year, but the simple math is around the buyback is that we've now reached a point this year at the end of 9 months where our breakeven position, including the full dividends of the scrip issuance was around $49 a barrel.

That gave the board confidence yesterday to support the initiation of the buyback program now since we always said that the offset of the scrip will be one of our first priorities.

And indeed, for next year, $50 a barrel, we're confident we can balance the books and indeed go lower than that if we need to.

And the simple math for next year will be assume capital in the range of $15 billion to $17 million.

If the oil price is around $50 a barrel, we'll be at the low end of that range, which means you reach around about $23.5 billion to $24 billion of operating cash post tax to get everything back into balance.

We may be slightly stronger than that given the trajectory that we're now on.

I hope that's answered the question.

I can't be more specific than that with Upstream, but that's sort of give you the sort of general flavor of where we are in terms of next year.

Then in terms of OpEx per barrel, I think we just continued to see in Lower 48 improvements around the way in which that business is run.

We've got the operating cash breakeven down to about $1.50 now, lower.

In fact, it actually was lower than that in 3Q.

And on a free cash flow basis, comfortable at $3.

And that provides us lots of optionality as to where we go next and the opportunity set that we have in Lower 48.

It's one of the activities we can ramp up relatively easily compared to other areas, and that will be a decision for Bernard and the team in the round in terms of what they lay out for next year.

Thanks, Oswald.

Turning now to Lydia Rainforth of Barclays.

And if I could just echo Oswald's comments about saying thank you as well for all your help.

Brian, just 2 questions, I guess.

Firstly, when you're talking about the allocation of capital, when would you actually look at buying back previous dilution?

And I know I'm asking for quite a lot there, but just the balance of the -- this program that's been in place for the last couple of years.

And then just on the cash flow numbers, if I ex out the working capital number, it does look like cash flow this quarter was slightly weaker than it was in 2Q.

I was just wondering if there's any sort of one-off impacts, either be it from Angola or from the flooding related to the hurricane in there that you could talk through.

Yes.

So maybe that second question first and I'll come back to buybacks.

3Q is typically a quarter where you have a number of payments going out like pensions.

You have some tax true-ups.

You did have the Angolan piece as well, while we haven't put a specific number on it.

So that will weigh a little bit heavier on 3Q cash flows than any typical quarters.

I think again, as I said earlier, a good proxy is EBITDA and if you look at the EBITDA track from 1Q through to 3Q, you've seen steady progress and steady increase in our EBITDAs in terms of -- and that's really driven by the projects coming on stream and continued underlying performance improvement coming through in the Downstream.

But you're right, it's a heavier quarter than typical in the third quarter because of pensions and tax payments that go out.

In terms of buybacks, what we've -- I mean, just to be absolutely clear, what we've announced today is that we now start the process, as we said we would, of offsetting the scrip on a point-forward basis.

But to be clear, and it's a conversation we've had at the board, we do have a mandate each year at the AGM to be able to buy back up to 10% of our stock.

And you'll recall that during the post-Rosneft transaction, TNK-BP, we bought back $10 billion to $12 billion of stock back during that period.

So buybacks beyond the scrip going forward is always an option for us, but that's really a consideration for the board.

And the board will want to weigh that up against further distributions to shareholders, alternative investments or paying down debt.

So that's available to us, it's in the round.

But just to be absolutely clear, what we've announced today is now on a point-forward basis.

We start to buy back the script, and of course, we can go further than that depending on what the overall shape of the finances and balance sheet is for the corporation going forward.

Thanks, Lydia.

Turning now to Irene Himona of SocGen.

My first question is on sensitivities, if I may.

Brian, your 9-month RCP rose about $5 billion or 2.5x year-on-year, but there were a lot of moving parts.

Brent was up $10, margins were up a couple of dollars, production up 10%, costs down 17%.

What updated guidance can you please provide in terms of your current sensitivity, earnings or cash flow, to the oil price or refining margin?

My second question, Rosneft, for your 1.1 million barrels of share in the production, you received in Q3 $190 million dividend.

Aker BP, following this latest deal, will give you around 60,000 barrels a day of production and a dividend next year of probably around $120 million.

So Rosneft gives you 18x more volume but only 60% more dividend.

In that context, I wonder if you can remind us, please, how you look at Rosneft and the value of that holding.

Okay, Irene.

I'll come back to that.

In terms of rules of thumb and being able to -- I mean, you're right to highlight there's a lot of moving parts this year.

I think we're getting back now into a more stable period and we'll update all of those rules of thumb for you with our 4Q results in February.

It'd be premature to do that now and there's a lot of moving parts, as you described.

Brent was up $10, but of course, TI quarter-on-quarter stayed flat this time around.

And therefore, some realizations were impacted by that in the U.S. as the Brent-TI spread opened up.

So we will update you on all of those.

We appreciate that there are a lot of moving parts around the hurricanes, the weather patterns around the globe that we saw this year, the various movements in the oil price, the gas prices.

But as I say, we will update all that come February.

And of course, you also saw this year around refining the Brent -- not only just the Brent-TI spread, but also the light-heavy spread coming into one of its narrowest ranges in a long time, which, of course, impacts some of the results out of Whiting, which signals potential upside into the future as that spread starts to move back out to more typical range.

But I completely empathize with you in terms of moving parts.

It's going to be difficult to reassess that until we get into next year.

But we are now getting to, I think, a more stable period of where oil prices are, and we've come through, I think, that most difficult period where prices came down from $110 a barrel down to $28 a barrel and have now moved back up into a range of around north of $50 and indeed now north of $60.

I think we'll continue to plan on the assumption of something around $50 to $55 on a point-forward basis certainly coming into next year because there's an awful lot of moving parts around demand and supply and how that will play out into 2018.

On Rosneft and Aker BP, the facts that you've laid out are absolutely correct, and Rosneft has now flagged up on a dividend basis that it will be 50% of its earnings are dividend now and it will do that on a base of 2 quarters.

So we get that in the third quarter.

We got a payment in the third quarter.

We're also expecting a payment this quarter based on the first half 2017 results.

I think you have to come back to the transition from TNK-BP into Rosneft, and Rosneft is one of our key strategic partners and strategic alliances that we have around the globe.

It's an incredibly important basin for the globe around oil and gas.

And in terms of an investment, we really see it as a strategic long-term investment, so don't look at it in the same way that you did in terms of comparison of Aker BP and Rosneft.

It's really about getting access to resources on the ground in joint venture operations with Rosneft going forward, of which we've announced a number in the recent years.

And that's really where we sort of see growth in terms of the investment that goes into that.

Of course, we also get a dividend and that dividend is very helpful, but we don't see it as being the reason why we invested in Rosneft is just as a passive strategic investment.

This is one of our key strategic partners, and we have a number of options that we continue to pursue with them in terms of growth for BP with Rosneft, alongside Rosneft in those basins.

Thank you.

We'll take a question now from Brendan Warn of BMO.

So just 2 questions, if I may.

Just first question just relates to, I guess, gearing and that you're obviously well within your 20% to 30% that still remains at the top end just in terms of your priorities of uses of cash for your balance sheet.

And then, I guess, second question just comes to what do you expect you're going to be getting for the $15 billion to $17 billion in terms of CapEx, in terms of capital efficiency and growth beyond sort of your 2021 and your delivery of the 7 projects?

Or do you need to be thinking about inorganic for further growth?

Great, thank you.

So first of all, on the gearing question, it's now sitting at 28.4%.

It's comfortably inside the range.

It's come down this quarter versus last quarter.

We would have anticipated net debt may have crept up a little higher than it did during the third quarter given that the big chunky payments around Gulf of Mexico went out in the first half of the year.

So $4.5 billion has gone out in the first 3 quarters.

So actually, if anything, net debt was anticipated.

We expected to come up a little bit through 3Q and then drop off significantly in 4Q with the disposal proceeds that have come in from particularly SECCO, the MLP from BP Midstream Partners that was announced last week and taken to the market, along with the tail of divestments where we're anticipating divestment proceeds of around $4.5 billion for the year, so $3.5 billion -- around $3.5 billion for the fourth quarter.

So therefore, you're going to see net debt continues to track down.

If anything in the third quarter, we had a $0.5 billion negative impact on the debt book.

So in actual fact, net debt did drop off $1 billion, but then we had a $0.5 billion reversal off the back of ForEx movements that happened at the end of the quarter.

So in the round, we're very comfortable where the balance sheet is.

We would not have signaled a buyback program today if we were concerned about the balance sheet.

It will naturally start to trend down now over the next few quarters.

If we look at the flows for next year, again, you're going to see Gulf of Mexico, the balance of just over $2 billion of payments going out in the first half of the year, disposal proceeds coming in, in the second half.

So it'll continue to be a bit lumpy going forward but the overall direction is downward.

So there's no concerns in terms of gearing and net debt, and that just simply reconfirms what we said in previous quarters.

If anything, 3Q has come in a little bit stronger that we anticipated on the balance sheet.

In terms of the project portfolio, of course, we have the 8 projects coming on stream -- 7 projects coming on stream this year.

We have the last one, Zohr, due this quarter and then we have 4 more projects that come on next year that then underpin the growth that Bernard and the team laid out for you earlier in the year.

But of course, our focus now is much further into the next decade within that frame.

Hence, you saw the licenses that we won last week in Brazil.

There were 2 blocks that we were pursuing.

We have managed to achieve both those blocks, one with Petrobras and CNPC and the other one with Petrobras.

That has got a huge opportunity set for us in terms of going forward.

And of course, we also announced Mauritania and Senegal at the end of last year in terms of investment, which again starts to fill some of that growth beyond 2021.

So the team are very much focused on the next decade now given that the project suite is pretty much in place in delivering out to 2021.

A lot of the focus on the team, both Upstream and Downstream, is on future growth into next decade.

And of course, we are expecting this year that the Woolworths transaction, the Downstream is likely to close probably into second quarter at some point, which will give us another growth node in terms of Downstream and sustaining that business going forward.

And of course, last week, you may have picked up Bob's speech that he gave at the Oil & Money conference here in London that talked about the other growth factors that we're looking at under Lamar McKay and Dev Sanyal around the renewable space and the low carbon space and some of the new technologies that will be available that we'll be able to bring our expertise to bear on.

So I think the team are very focused on the next decade.

The next 3 or 4 years, we just need to focus on delivering what we said we'd deliver at the start of this year and that's really what you've seen reflected in today's results.

Thanks, Brendan.

Now we'll go to Christyan Malek of JPMorgan.

So 2, if I may.

First, coming back to BP's medium-term CapEx outlook, Brian, you mentioned the lower investment frame for the group is possible in a lower oil price environment.

What's stopping you from lowering CapEx further if you can continuously apply incremental technologies and efficiencies?

I understand the cyclicality of CapEx, but if you're so confident on your long-term production outlook, I struggle why -- with why you can't lower CapEx further with or without oil below $50 a barrel.

The second question is, to what extent is your buyback plan a function of oil price?

For example, if we head back to low $40s Brent, what sort of quantum of buyback would you offer?

So put in another way, is buyback a fixed feature within your capital framework?

And would you choose to flex other targets, for example, gearing or CapEx?

Thanks, Christyan.

Maybe -- so first of all, in terms of capital, I think that's a very fair push in terms of where we are.

And actually, if Bernard were here, he'd talk you through the things that they're doing in terms of driving that capital down and lower.

We will continue to see benefits come through in the technology space.

If anything, what we've learned from the last 3 years from a number of the things that we deployed that were laid out at the end of February that Bernard had in his presentation, a lot of those things are now active and in place.

And I don't know if you recall the video that was played.

Actually, a number of those things are actually here in trains.

So there is no question we're going to continue to drive capital efficiency through that lens.

That simply gives us upside going forward.

But I think a frame of $15 billion to $17 billion and the growth profile that comes with that is a pretty reasonable place to be.

If the oil prices are $50 next year, the capital will be down towards the low end of that range.

If it's below $50, it will be below that range, just to be clear, which comes on to your second question.

The buyback featured today is very simple.

It's taken us 2.5 years to get the company back into balance, with a revenue stream that went from $110 a barrel down to $28 a barrel.

I was talking to somebody this morning about that.

I mean, that is quite a move that any sector or industry would have to go through.

To now find ourselves within 2.5 years to now get back into balance and honor the commitments around the dividend, I mean, the dividend is not there just to be created as a dilution mechanism.

And therefore, we have to offset that dilution going forward to ensure that we cover the full dividend.

So what you heard today is absolutely we will now be covering the full dividend going forward.

The scrip will be offset.

The board, we have discussed whether we continue with the scrip or not.

We think the scrip dividend is something which our investors, in some quarters, have taken up to 45% scrip.

So it's attractive to investors in certain quarters.

There are benefits for them, both in the ordinary shares and in ADRs.

We've seen up to 35% uptake in ADRs.

It's also created financial flexibility for the corporation, but we recognize that in the sessions we've been having with investors over the last few quarters, we recognize that, that dilution weighs heavy on the holding in the stock.

And therefore, with a dividend of around $8 billion, it's right that we should start to offset scrip going forward.

So irrespective of where we are in oil price, you should assume we'll be offsetting scrip.

Now we can manage that for next year down to $45 a barrel.

We're comfortable we can do that.

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

I think it's more likely being in the $50, $55.

But the intent today is simply to announce, as I said earlier, that we will start that buyback program now to start to offset that dilution for shareholders going forward.

And buybacks are an option for us in terms of the overall armory in the broader financial sense over the next few years as the additional projects come onstream, as Downstream delivers the underlying performance that's been laid out for you at the end of February.

Just not to put words in your mouth, but so can we assume that up to sort of below -- at $45 a barrel, scrip a fixed feature below $45 a barrel or just...

Christyan, I wouldn't lock it into fixed feature.

We have a dividend of $8 billion right now with the number of shares that we have in issue.

We need to pay that dividend on a point-forward basis.

If the oil price is down at $10, that's a whole new world.

So I don't think you want to get into a fixed feature or a certain price.

The intent from the board today is very clear.

On a point-forward basis, we'll be offsetting that scrip.

Thank you, Christyan.

Turning now to Michele della Vigna of Goldman Sachs.

Two questions, if I may.

The exploration expense was very low in the quarter at around $300 million.

The previous 2 quarters was around $800 million.

I was wondering what you consider to be a normal level of exploration expense.

And then secondly, you are delivering very well on the current pipeline of projects.

I was wondering which projects do you now feel ready to sanction in the next 12 months for your next generation of growth.

I think on the next generation of growth, I'm going to hold that to the fourth quarter results because as we sort of work our way through the projects for this year, we have the projects coming on next stream, the number of FIDs in track, but I think I'll save that for the fourth quarter, if that's okay.

We talked about previous FIDs, which were coming up in previous quarters.

But I think 4Q is a good opportunity for an update on that.

On exploration expense, do you mean -- if you can be clear, Michele, you're talking about exploration write-offs or are you talking about investment?

Write-offs.

So write-offs typically are more -- a typical quarter where you don't have major exploration write-offs would be something around $300 million to $400 million.

This is actually quite a low quarter.

I think it was about $70 million or $80 million from memory.

Actually, maybe even as low as $30 million for the quarter, $34 million.

A more typical quarter would be $300 million to $400 million.

Of course, we've had some pretty lumpy ones, like last quarter, we had a $700 million write-down around a specific region.

But you should assume something around $300 on a point-forward basis.

$300 million to $400 million is a reasonable number to assume without any major write-offs associated with specific assets.

It's probably worth pointing out that we have a large inventory of intangible assets that we're working our way through some of those.

And of course, as the oil price changes and as technology moves on, a lot of those assets come into the frame in terms of potential FID and moving those projects forward.

So I think something around $300 million to $400 million is a reasonable sort of number to assume on a point-forward basis.

Thanks, Michele.

Now to Jon Rigby of UBS.

Go ahead, Jon.

Two questions, one bigger picture, one sort of minutiae.

On the bigger picture, you highlighted 2 relative successes in the quarter on a sort of extended structural basis.

So you've launched the MLP, and clearly, Aker BP is really going great guns.

So I just wanted to ask you about at the sort of board level where you see -- how you balance the ownership, direct ownership of assets and operations and where you feel comfortable to hold things at a rather more arm's length basis and take advantage of that and how you balance those 2 things, if that's possible.

The second thing, I think, in the accounts, you talk about how SECCO will now be treated as an asset for disposal when we take out the 4Q.

So I just wonder whether you're able to indicate what the contribution of SECCO was to petchem results in the third quarter, just to triangulate my forecast.

So the second question is a spreadsheet question, Jon, which I'll be very happy to answer because I think that will help everybody on a point-forward basis.

So I'll come back to SECCO once I find the sheet for it, but there will be one knocking about somewhere.

On the MLP and Aker BP, I think they're great points to make.

I think everything comes back to value over volume and the sort of mantra we put back in place as we rebuilt the company over 2010 to 2014.

So that while an output of that at the moment over the next 3 or 4 years is significant growth, and you saw that come through in this quarter and year-to-date 7% growth on an underlying basis in terms of the Upstream, having laid that mantra out, we're pretty much sticking with it.

And I think Aker BP and MLP are 2 very different structures that we have in place.

Nevertheless, they will both open up new growth opportunities for us that we probably wouldn't have been able to achieve as a sole owner.

I think Aker BP is a great example of one where 2 leaders came together to bring that deal to fruition originally with Bernard and Øyvind.

And in terms of what's now being created as a growth option for us going forward, I think what you saw last week is a great example of really where that company is now heading.

And we've taken a basin for BP in terms of where we were with Norway, probably had limited growth available to us as BP.

But now in joining forces with Aker, we've created a real growth vehicle for us and we'll be able to participate in that growth.

And the ultimate benefit we get is through the dividend that Irene flagged up earlier in terms of that coming through.

MLP is very different.

I think that will provide options.

It's allowed us to monetize an asset.

It's a strong market.

Nevertheless, last week, when we launched it, we sort of hit a relatively weak market but certainly hit the prices that we were looking for.

And that will give us opportunities going forward as other companies have seen with the MLP market in terms of potentially moving further assets into that structure going forward and creating a different sort of growth vehicle from the one that you saw with Aker BP.

I think in terms of the board conversations, the board is very open to a number of conversations we've had around various structures that we've looked at with the company ownership.

But I think value is going to be the ultimate driver as to which direction we go to around particular assets.

In terms of SECCO, it has actually been moved into asset held for sale, mostly because we're almost due to complete the sale, so it has actually sort of come right in.

And for the third quarter result, its earnings -- its year-to-date earnings are just under $300 million, is probably the number I can give you, which will maybe help you then in terms of point forward.

It would be -- the first 3 quarter earnings is going to be around somewhere around about $270 million is what you'd have for the first 3 quarters.

Thanks, Jon.

Next question from Theepan Jothilingam of Exane.

Two questions, please.

Firstly, just coming back to the BEL's claims and just intentions in terms of closing that facility, if you could perhaps, Brian, give any sort of time line on that.

And then secondly, with the success in Brazil and the third round of the pre-salt, again, could you give a little bit of color in terms of sort of activity, when you expect to be able to sort of drill on the acreage?

Great.

So on the latter one, in terms of Brazil, it's probably a bit premature for me to say where we are on that.

All I'd say is the team are very happy that we actually won those 2 blocks since they targeted 2 blocks and they're the 2 blocks that they achieved.

And it's in a very prolific -- and I'm sure you know this, it's in a very prolific part of the Santos basin.

So on that basis, I think there'll be a lot more to discuss.

And I'm sorry to defer this off 4Q, but I don't want to steal Bernard's thunder this quarter, but I think he'll talk you through what that will look like in terms of potential drill-out and what the -- what we've actually committed to as part of those licenses.

But there will be more to follow at 4Q.

And I hope that's okay, Theepan, I can't really sort of go into much more detail than that.

On the business economic loss claims, we're really into the tail now.

If you recall at the start of this process 5 years ago and we were discussing this yesterday, we had about 147,000 claims that was sat in that facility.

There's been a little bit of a delay in finalizing the last tranche of those with Hurricane Harvey and a bit of a slowdown with the settlements and the payments out in the third quarter, but we're down to now about 1,800, 1,800 of 147,000 to resolve.

We should know by the end of this year what the total landscape looks like of what those claims count to.

Some things will count to 0, some things will have a set -- have a number associated with them.

And then we'll also -- we'll be able to see what our total appeals bucket looks like versus what's left inside the provision, and then we'd be able to do a revised provision at the end of 4Q is the position we'd be in.

But we are really now into the final tail of that claims process, and we've actually gotten now, of course, the full projections of what the actual cash flow looks like for next year.

The only final uncertainty really remains around those final 1,800 claims and what the -- what effectively appeals bucket looks like versus what we have left provided.

And that will be a separate process that we'll go through, through probably the fourth quarter and first quarter.

But we should be able to update at the end of 4Q.

Thank you.

We'll go now to the Rob West of Redburn.

I'd like to ask -- I kind of want to ask 3, if that's okay.

The first one is really quick.

Just on the buyback, you alluded to the board conversation yesterday and the intention to dilute the scrip on a point-forward basis.

Did it come up at all just to get rid of the scrip?

And can you tell us anything about that discussion that's pertinent?

The second one is on the Downstream strategy where you really took us under the bonnet earlier in the year, 3,000 service stations to add, 2,000 convenience stores.

Since that time, a lot of your competitors have also announced plans to reverse the trend of divesting from fuel retail and follow what's the similar strategy.

Do you share that perception?

And is it, in any sense, changing anything for you in terms of how fast you pursue it?

And the final thing I was interested to ask is just ADNOC is currently pulling into view now, I think, 6 months away from that license.

And do you see that playing out like ADCO or anything you can share with us there?

Yes.

Jess is telling me only answer 2 questions, but we'll see.

She is getting tough.

You can pick your favorite 2.

Well, I'll take them in order, and then actually, I can -- actually, we'll leave the ADNOC one to 4Q.

But in terms of first Q, so we have had a conversation with both investors and the board and our advisers around the scrip.

The scrip was introduced.

The end of 2009 is when the board approved it -- not approved it, it was discussed with the board at the end of 2009.

It was introduced in 2010.

What is clear from our investors is there is a large group that liked the scrip because it's efficient for them to take that scrip as an alternative to a cash dividend.

So we don't want to stop that part of this because ultimately, we'll be driven by what investors believe.

Equally, there is a large proportion of investors, including the same ones that take the scrip, that would say, but if your dividend is $8 billion, you need to offset that dilution.

So the intent is absolutely to pay out an $8 billion dividend.

And as part of that, therefore, offsetting the dilution associated with the scrip.

We'll continue to talk to our investors.

If our investors come back and say actually, no, and they have an opportunity to vote at this at the Annual General Meeting every 3 years as to whether we offer a scrip alternative.

There now will be a conversation decision by shareholders that they will ultimately take.

But for now, I think the key here is we're now in a position, after 2.5 years, to get the balance of the finances back into balance and we can declare that actually we can offset that scrip on a point-forward basis.

But there is a strong push from investors for that scrip to continue to be available, not only just in terms of ordinary shareholders where I think I said earlier the uptake has been as high as 45% in some quarters, but also the ADR shareholders have been as high as 35%.

So we'll continue to offer it while investors continue to vote to make that available to us as an option.

It's been helpful in terms of managing the financial frame through the transition to these lower oil prices, but it's something, again, it's really a matter for investors and they'll get -- they'll actually have a decision choice around that going forward.

And the board have discussed this at length about removing the scrip completely or just a simple offset of dilution.

I recognize there was a friction cost associated with both issuing shares and then buying those shares back, but it's relatively de minimis in terms of the overall scheme of things in terms of flexibility it provides both to shareholders and for the company.

On Downstream disclosures, I think you'll see more around Downstream going forward annually.

I mean, I think as you said, Tufan well and truly opened the bonnet and pretty much showed you every moving part of the Downstream at the Downstream investor day.

On an annual basis, he will update you on progress on those.

I can't comment what other companies are doing.

What I would say, though, is it's very clear as we go through a major transition over the next decade, staying close to our customers because sometimes we forget we have more customers than some of the big huge retailers like Starbucks.

We actually have more customers per day coming through our facilities than some of those really big retailers.

Ensuring that we continue to stay connected to those customers on a point-forward basis through the various transitions that we're likely to see, if not around the whole energy mix going forward, is going to be a massive opportunity set for us.

And I think today, we have anywhere from 10 million to 15 million customers per day coming through our facilities.

We just need to make sure that we continue to provide offers that are attractive to them to make sure that they continue to keep on coming through these facilities.

Thanks, Rob.

Next question from Martijn Rats of Morgan Stanley.

I wanted to ask you 2 things.

First of all, could you talk a bit about this extraordinary Downstream result?

Because, of course, during the quarter, we had the hurricane impacts and as a result, it's an exceptionally strong number but I find it quite difficult to read.

Is it possible to strip out perhaps the effect of the hurricane impact on that Downstream result?

Is there something else that is going on that inflated the results in this quarter?

And secondly, I wanted to ask you about the Upstream.

Is there any sign of inflation visible yet outside the United States?

I'm sorry, what was the last question, Martin?

Say that again?

Yes, the second is are you -- is there any sign outside the United States of any inflation in oil-field service costs, wages, taxes?

Are there any inflationary pressures already emerging in the market outside the United States?

Okay.

On Downstream, the hurricanes had a relatively limited impact on the results.

So I wouldn't sort of go to that particular place because notwithstanding we don't have any Gulf Coast refineries anymore, but there were huge refinery outages.

But of course, demand was also destroyed as a result of that.

So you sort of have both sides to the equation covered.

So we will have got some benefit through slightly higher refining margins, but a lot of that was negated by the point I made earlier around light-heavy diffs.

So I think the only place to go to in terms of Downstream is to say there's sort of 3 sources, I guess.

One is stronger margins in terms of refining overall.

The RMM was higher but it was offset by the weaker light-heavy spreads and some local margin impacts.

Stronger fuels marketing result that came through.

We had a lower turnaround quarter in the third quarter, which would have showed -- which would have been in the sort of would have had a small impact on the result in sort of the 100 million type, 100 million, 200 million type zone.

And we got a stronger trading result.

The 2Q result was weak for trading.

It was below plan, but it was above breakeven.

So it was sort of a weak quarter.

This was a stronger trading result, but it was just above plan so wasn't a sort of blowout quarter in terms of the trading result.

But the delta quarter-to-quarter, you would've seen a move certainly from the stronger trading result.

But it was also refining margins, and again, continued strong fuels marketing performance.

In terms of inflation outside the U.S., we're not at the moment, but of course, as you start to see oil prices start to tick up, we stay ever vigilant in terms of where we are around the costs and making -- our cost levels now in the Upstream are back to where they were when it was back at $45 a barrel a decade ago.

So Bernard and the team have brought costs down quite significantly, and we'll continue to stay focused.

The things which will balance out any inflationary pressures that you might see will be the things alluded to earlier around technology and what we're deploying in the way of technology across the piece and continued focus on costs across the piece and efficiency.

But we're not seeing anything outside the United States right now.

Next question from Biraj Borkhataria of RBC.

I had a couple.

First one on Macondo again.

Could you just talk about -- I know you gave the number of claims left by the end of the year, but is there a risk that you come in toward or slightly ahead of the top end of your guidance of $5.5 billion?

This quarter again was slightly higher than I was expecting.

And the second question on U.S. onshore, how is that competing for capital relative to some of the opportunities you have?

Costs continue to go down.

So I was wondering if that is moving up your priority order for growth.

Yes, maybe the latter of those 2 questions.

I alluded to earlier, I think U.S. onshore, the team have done a terrific job over the last 3 years in terms of positioning that business, and that is always an opportunity set for Bernard and the team.

If you want to ramp up activity quickly, that's one place you can do it.

So again, I think I'd leave that for the fourth quarter.

We can talk about then where we've got to in terms of plans for next year.

But it's absolutely, you're completely right, that's one opportunity for us in terms of ramping up activity if that was something we chose to do, depending on the environment that we see.

In terms of Macondo, we've given you an estimate now for the full year of we think it would be around about $5.5 billion, so I don't think -- I can't give you any more revised estimate other than what we laid out today.

I think the balance of risks, upside and downside, I think that's a pretty good number for the year in terms of where we expect 4Q to finally come out.

Thanks, Biraj.

Next is said Thomas Adolff of Crédit Suisse.

Two questions as well, please.

Firstly, on Upstream production, when we look at BP ex Rosneft and look to, say, 2022, Upstream production is growing and is growing nicely.

But I wonder, if we were to deconstruct the profile, do you see between now and 2022 BP's oil production curve roll over since, obviously, many of your projects are somewhat more gassy?

And perhaps you can also comment on decline rates in your portfolio.

And if you say no, I wondered on a global basis, not just for BP, whether you see the oil production curve roll over by the early 2020 at, say, $60 Brent.

And secondly, on Brazil, and I know you don't want to talk about Brazil in detail on this call.

On the 1Q call, I had asked you about Brazil and you didn't really give a proper answer then since, obviously, you've won some nice licenses in the third bid round, and I wonder whether it's just the beginning and more will follow.

And strategically, should we consider Brazil as one of your next kind of key hubs?

Obviously, Peroba is potentially large and you'll talk about it on the 4Q call.

But obviously, there are a lot more bid rounds in the next few years in the pre-salt as well and other direct opportunities.

Okay, Thomas.

Well, thank you for the coaching on the first quarter call and I'll take your coaching in terms of not giving you proper answers.

And I'll try and make this one as proper as I can in terms of covering it.

I'm not sure I can give you any more on Brazil.

I think we've won the 2 licenses last week.

I think it gives us huge optionality going forward.

I think Bernard will talk about it in the 4Q results, and the team will continue to look at other opportunities around bid rounds.

But those 2 blocks were ones that were targeted ahead of time and the team won and I feel pretty good about it.

And we'll look at what the next round looks like.

But that pre-salt in that particular part of the Santos basin is really interesting for us.

So I think that's -- I can't really give you any more detail than that, but there'll be other bid rounds in other regions that we'll be looking at and the team will continue to focus on.

Because, of course, that's the point I think you trying to push on, which is the 2022 and beyond is really kind of how we now feel that growth curve.

Because this sort of comes back to your first question.

You asked about decline rates, and of course, they're very different across the gas portfolio versus the oil portfolio.

We plan a decline rate of around 3% to 5%, which we have done for a long time.

Decline rates are actually running below 1% year-to-date or around 1%.

So they are actually running quite low.

I think that was intuitive.

We should have probably figured that out maybe 2 or 3 years ago as we came into the oil price correction and for everybody focused on the near-field developments and infield developments has led to a lower decline in previous years.

I think this year, and I'd come back it's probably a question worth asking of Bernard at the end of the quarter, but I suspect this year, what we're starting to see is real benefit to come through from technology and the technologies that we're deploying, which is allowing us to get better reliability in the drilling and the kit that we have.

And I could give you a number of examples around sand management and what we've deployed in that space with some of the technologies that we've developed over the last 2 or 3 years.

I think that's definitely helping drive down decline rates and what you see today.

What the profile will look like out to 2022, of course, will be a big function of what the next big round of FIDs are over the next 2 or 3 years.

And I think we'll lay those out for you in the fourth quarter, which will be a good time to do that.

A quick one on just predictive maintenance...

Is that a third a question, Thomas?

Is that a third question?

Jess is looking at me, but go ahead, predictive maintenance.

Predictive maintenance is also a big thing in, obviously, managing decline rate, if you will, or operational efficiency.

I mean, what's the size of the price, if you will, on predictive maintenance across the entire portfolio?

Well, I think if you get back to that video that was played at February, that was a big part of it.

And I think the technologies that we're now deploying into the well portfolio we have will allow us to start to look at not only predictive maintenance but performance of specific valves that we have within our inventory, and it all comes back to procurement supply chain management.

So I think the opportunity set is huge for us because -- and I say it's huge because, ultimately, the ability to do that and understand the kit that we have deployed across those 2,200 wells in the portfolio will create better reliability of the kits.

So not only does it arrest the issues around decline, but it just gives you more uptime in terms of production.

And that, of course, drives ultimate earnings, which is what you're actually seeing in the third quarter.

Thanks, Thomas.

Next question from Alastair Syme of Citi.

Where do you think cash tax will end up in 2017?

And do you think that will change meaningfully in either direction going into 2018 at that $50 to $55 oil?

And my second question, a little bit longer, we're coming up on the end of the year and I think we've had this discussion before around the fair value analysis that's embedded in the balance sheet at $75 reel.

No doubt that's helping the gearing a little bit.

Accepting that oil prices have moved in the right direction in the last couple of months, do you feel the need to align the view to one that's closer to what you show on Slide 15 around $50 to $55 oil?

Yes.

On that later question, we actually do, and actually, we just went through it this quarter.

We have significant headroom across the whole asset portfolio.

And the tests that we run, which I think is where your questions originated from, the test we run is actually on a forward curve basis out for the first 5 years.

Actually, we sort of -- we smoothed the line out 5 years, but we actually use prompt 4 or 5 years in terms of carrying value of the assets.

Was that the source of the question, Alastair?

Yes, it is.

So there is more than significant carrying room.

And actually, we reviewed it last week with the Audit Committee across the whole suite of the portfolio.

So I don't see any issues on that side.

And like I say, $75 is a long-term assumption that we use.

But actually, for impairment testing, we actually use something more near-field in terms of the forward curve, which, of course, has helped versus a year ago because it's moved up $5 or $6 from where we were.

But there is still, based on what we ran at 3Q, sufficient headroom across the whole portfolio.

So just to clarify that, that's 5-year forward and then $75 a reel?

Is that what you're saying?

Correct, that's correct.

And the 5-year forward we modified last year to be more in line with the rest of the sector where it's actually smoothed across those because the forward curve is not particularly liquid beyond 2 years.

So for that year, 3 to 5, we just smooth.

Because otherwise with no liquidity out there, it'd be, I think, you -- it's a better way in which -- well, better.

It's a good way in which to analyze what the forward projections look like.

And then on the cash tax rate, I think we'll just wait to where we true-up this year.

Typically, pre-Abu Dhabi, when our effective tax rate ran at around about 33%, 35%, our cash tax rate would run at around 26%, 27%.

With Abu Dhabi now in the portfolio, we'll get a year of that at the end of this year and we can come back.

Cash tax rates typically run lower than your tax charge for a variety of reasons.

There's a lot of moving parts in the cash tax this year, particularly in the third quarter, which impacted operating cash flow.

We'll be able to -- once we got 4 quarters under our belt, we'll be able to give you more guidance around that in terms of next year.

But it will typically run 6, 7, 8 percentage below point -- below the actual charge of -- this year, we're giving indications of just over 40%.

We expect the tax charge to be with the Abu Dhabi concession in.

Tax rate will typically run below that, but we'll be able to give you a better handle on that at the end of the year when we got all 4 quarters under our belt.

Thanks, Alastair.

Next up is Chris Kuplent of Merrill.

Are you there, Chris?

I'll try and keep it brief.

Brian, the $5.5 billion expected oil spill payments this year were obviously meant to be financed through disposals, of which you've highlighted $1 billion received so far, another $2 billion-plus to come through in 4Q.

We've only got 2 months left.

Obviously, not asking you about exact transactions pending or in your drawer, but are you at all worried about a $1.5 billion or so gap still in your $4.5 billion disposal target for the end of the year, if I get my numbers correct?

And second question, similar line, obviously, you also have M&A outflows this year and I wonder how they are funded, a, and b, how they are accounted, in particular, that sign-on bonus on ACG.

Is that already in Q3 results somewhere?

How are you going to stretch that out going forward in inorganic or organic CapEx, please?

So on the disposal proceeds, very confident around the 4.5%, Chris.

You will have probably picked up from the earlier conversations, SECCO, $1.4 billion, $1.5 billion of proceeds coming in this quarter, deal about to close.

MLP, master limited partnership, now in the marketplace, over $700 million of proceeds coming in.

Tail of a number of other disposals, which we flagged up at the start of the year, all the cash arise for those.

Some of those have been announced.

But the tail of those will come through.

So the $4.5 billion is a pretty good number for the fourth quarter.

The frame we laid out was disposal proceeds would cover Deepwater Horizon payments over time and they would not necessarily be symmetrical in year.

So therefore, next year, you will see further proceeds coming through to balance that from this year, but you'll also see Deepwater Horizon payments going down quite significantly next year.

So the balance will be in the opposite direction for 2018.

So yes, pretty confident on the disposal proceeds and it always helps when the cash is in the bank and that will come through in the next 8 weeks.

And in fact, actually, a number of those transactions will come through in the next few weeks actually.

And then on the M&A outflows, the ACG bonuses paid over a number of years.

From memory, I think it's over the next 5 years is the way in which -- 8 years, sorry, the way in which it's structured.

So you'll see that flow out.

And that is phased over 8 years as a payment in terms of bonus and the first payment is due -- I think it goes out in the first quarter but I need to go back and check with the team on that.

And then in terms of the other M&A outflows, they will be covered inside the inorganic frame that we've laid out.

So the Woolworths transaction that we've laid out that we anticipate will close at the -- in 2Q, the Downstream will come up with a suite of disposals of tail-end assets that will cover that investment, and that will be the same in the Upstream in terms of any further M&A activity.

So I think we have a very clear frame now where operating cash flow covers dividend and capital and the scrip.

So you've got complete balance on that side of the equation.

And we'll continue to use M&A, both on the positive and negative side, in terms of selling and buying assets.

And in terms of Deepwater Horizon, we're now through the $13 billion that we had to spend last year and this year, hence, where net debt has got to.

That payment schedule looks like just over $2 billion for next year, front-end loaded, first half, and then $1 billion -- just over $1 billion a year out to, I think, 2032, 2033.

I think, from memory, I think it was 2032, 15 years.

And effectively, that's done.

So that -- I think the frame is clear.

We've now delivered against that frame in the first 9 months.

As you see proceeds come in the 4Q, you'll see net debt drop down.

So I think from a balance sheet perspective, we're in a much stronger position than we would have been coming into this year and I think we've done the things we said we were going to do.

And as I said earlier, this quarter's coming a little bit stronger, which meant we've been able to initiate the buyback program a little bit earlier.

I'm sorry, Brian.

Just for clarification, sorry, the ACG bonus, that is part of your $15 billion to $17 billion framework going forward, right, not in inorganic?

The ACG acquisition?

The sign-on bonus.

Is part of that would be in -- no that would be part of the organic capital frame.

Thank you, Chris.

Next question from Jason Gammel of Jefferies.

Jess, best wishes for all your future endeavors.

Pretty major milestone accomplished during the quarter with the extension of ACG.

So I just wanted to ask a couple of questions related to that.

First of all, how do we think about the economics of the transaction, Brian?

Obviously, taking a lower equity position and making the bonus payment and then also getting the 25-year extension.

What would you expect in terms of an economic return from the transaction?

And were there any fiscal enhancements that you received in the transaction, which I believe resulted in a new PSA?

And then finally, would you expect to be able to take any reserve bookings in 2017 as a result of the transaction?

Thanks.

So if you look at the transaction, effective what we've renewed now is out to 2049.

I think our interest is now down to just over 30% from above 35% from memory.

I think we were close to 36% before and we're down to just above 30% now.

Although we've diluted our position in ACG, the profit share terms have improved.

So on that basis, the economics still look good going forward.

We'll continue to remain operator, and as we've said, we have the sign-on bonus that was flagged earlier and we just need to come back around how the sign-on bonus is treated.

I think a part of it may be inorganic, but I need to go back through the Upstream just to check on that last question.

But it's an incredibly high-quality discovered resource.

It's a great position to have.

What we've signed is equivalent to a $5 to $6 a barrel acquisition cost that we announced as part of the announcement.

And I think it gives us huge optionality in terms of the next growth into the next decade on what is incredibly important oil part of the portfolio.

And on reserve bookings?

That's probably premature at this point.

We'd need to come back and we'll update you in 4Q.

And I don't mean to push things off to 4Q but we now go through our whole reserves process this quarter.

So we'll be able to give you more on that in the fourth quarter.

Thanks, Jason.

And thank you, everybody, for your patience.

We just have only a few more people on hold.

So we'll try and crack through that as soon as possible.

And with that, we'll take a question from Anish Kapadia of TPH.

First question was on the working capital.

If I look back over the last couple of quarters, I think you've had close to a $3 billion underlying working capital gain, which has helped the balance sheet to some extent.

I was just wondering if you could discuss the factors behind that and if you expect any significant changes in working capital going forward?

And then second one was going back to the CapEx guidance for next year.

So you've got a $2 billion flexibility within your CapEx guidance for next year.

Can you just talk about what are the key flexible elements in that for 2018?

And so in a higher oil price scenario, what other things that we should expect to see coming back?

Would that be more exploration, more Lower 48 spend?

If you could kind of give some of the kind of key elements of the upside?

Yes.

On the latter question, I don't want to defer this out to later in the year, but I think we've already alluded to the fact that if we wanted to ramp up activity, the place where we could do it easy would be on the onshore, and therefore, sort of lead you towards Lower 48.

So there's no question we have opportunity sets there where we can ramp up activity.

There's other parts onshore where we can ramp up activity.

So there's various things within the frame.

But we're going to manage the frame pretty tightly.

So I don't think you should assume necessarily if we see a higher environment, we're necessarily going to ramp up capital.

We're certainly going to stay within the $15 billion to $17 billion.

But within that frame, we'll be pretty disciplined about how we deploy that capital.

And then the first part of your question was around working capital, which I think you'll find for the first 3 quarters, we released about $1.4 billion is the total release of working capital.

We believe that will be sustainable going forward.

We'll continue to look at opportunities around working capital to get more efficiency in our procurements and supply chain.

So to the degree that we can get more efficient in that, you may see further increases, but we're not anticipating anything in terms of where we are now.

In the fourth quarter, we also see a movement of capital that goes out with the mineral oil tax in Germany where about $1.5 billion flows out at the end of December and then flows back in, in January and February.

So there's a sort of one-off impact in the 4Q and 1Q where you sort of see a build as that money flows out and then it comes back in again within 60 days.

So you will see that effect in the fourth quarter.

But no other major impacts that we're seeing going forward.

Thanks, Anish.

Jason Kenney of Santander.

Are you still there, Jason?

Yes, I am.

Jess, all the best.

Just a short question.

When do you think that you're earnings per share will cover your dividend per share on a quarterly basis?

That's a great question, Jason.

Of course, what you're going to is, well, where does DD&A sit and what does DD&A look like going forward?

Because, of course, that will be the biggest driver in terms of that.

You're going to see that start to trend.

Obviously, the overall payout ratios will start to trend down.

As you see the growth profile start to get delivered over the next 1, 2 years and you'll be able to track that quarterly going forward, a big function of that will actually be what's actually happened with the DD&A, which will naturally start to increase.

On a per barrel basis it will stay flat, but will naturally start to increase as that new investment goes into those new projects.

So it's a sort of dynamic balance between the 2, but the payout ratio will naturally trend down.

Okay.

And if I could follow up, is there kind of P&L tax rate that you're thinking about at $50 to $55 for next year, 2018?

We'll come back to that with our full year guidance, but something around 40% is probably not -- in terms of planning at this point, 40% is a good number to kind of track slightly above that this year, but I think 40% is a good number going forward and we'll update all of those numbers at the end of 4Q with the guidance for 2018.

Thanks, Jason.

And we'll take the last question from Colin Smith of Panmure Gordon.

First, really, a point of clarification just around all the commentary on scrip.

Are we to understand that basically at $50 to $55 Brent, we'd expect the scrip to be fully offset by share repurchases?

And then my second question is just coming back to ACG, can you just clarify what the score is with the deep gas potential in ACG?

Okay.

In terms of scrip -- I think on scrip, what we've been very clear about is we'll be offsetting the scrip on a point-forward basis.

And I'm not going to sort of give you an oil price range.

Certainly, at $50 a barrel, we'll be offsetting the scrip.

At $45 a barrel, we believe we can offset the scrip because we can manage capital lower.

Beyond that, it will be a matter for the board what the choices are around how we deploy cash within the balance sheet.

But you should assume on a point-forward basis that we will be paying out the full dividend, therefore, offsetting the scrip.

In terms of gas potential, there are, of course, deep gas resources also that come along with those ACG fields.

And I think there will be more to follow on that post conversations with SOCAR when we get to the fourth quarter.

I feel like I've deferred a lot out to fourth quarter but that one is so current that we'll be able to give you an update at 4Q in terms of where we are vis-à-vis SOCAR.

But there is no question there are deep gas resources associated with those assets.

There'll be more to follow on that.

But to be clear, that wasn't included in the amended PSA terms.

So terms for the gas are still to be agreed, is that correct?

That's correct.

Thank you, Colin.

And that brings us to the end of our Q&A.

For those that are still on the line, I'd like to say thank you.

It's been a privilege to be in this role and to know you all over the years.

And I wish you all the best in the future as you hopefully continue to follow BP.

Great.

Thanks, Jess.

And maybe so, therefore, just to summarize for the quarter.

I think it's been a strong quarter in terms of delivery.

It is just a quarter.

It's just simply a 90-day period, and it's now 3 quarters into the 20 quarters that we laid out for you at the end of February.

I think we're making good progress.

I think the fact that we've got the company back into balance is an important signal for the marketplace.

And I can't think of a better set of results that Jess Mitchell would've been on the call for, for our last call.

Jess has been in Investor Relations now for 61 quarters, that's quite an achievement.

And I know Jess has done 24 quarters because we both started at the same time, and now she is leaving and that is a massive gap to fill, which we're very comfortable Craig will step into with his experience in both the U.S. and the U.K. markets.

But she has been a fantastic stalwart in terms of the Rock of Gibraltar for the corporation and for all of our people and has led our team incredibly well, which I'm sure you all know.

She is deeply liked and loved by her team.

She has built a great team around her.

I think you see the benefits for that certainly on the sell side and the buy side in terms of investors.

And I think if simply to summarize, a great testament was at yesterday's board call.

At the end of that board call, the board recognized all of Jess' contributions to the company's through some incredibly difficult times over those 61 quarters and leading the company through the last 24 quarters and 2 phases of rebuilding of the company, the 10-point plan.

And now I think it's quite fitting that the company has got itself back into balance as Jess has chosen to retire at this point in time.

We'll miss her dearly and I would not be surprised, post her retirement with BP, if she turns up back in some sort of area around Investor Relations, given how highly she is held both by our board, but most importantly, by our investors and how she has been able to portray the company over that period of time.

So I'd just like to add my thanks to Jess for everything that she's done.

Thank you for those kind words, Brian.

And with that, thank you very much for listening to the call today, and there will be an appropriate time where you'll be able to celebrate with Jess as she retires from the company and moves on to other things.

Thank you.