英國石油 (BP) 2018 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 Craig Marshall, Head of Investor Relations.

Welcome to BP's Third Quarter 2018 Results Presentation.

I'm Craig Marshall, BP's Head of Investor Relations.

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

Before we begin, I'd like to draw your attention to our cautionary statement.

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

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

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

These documents are available on our website.

Now over to Brian.

Thanks, Craig.

It has been another quarter of steady progress against the targets we laid out last year.

The focus on safe and reliable operations and strategic delivery, alongside an improving price environment, has driven strong underlying earnings and operating cash flow.

We'll start today with some comments on the macro environment before moving to highlights from the quarter and then covering our financial results in more detail.

We'll then provide an update on our operational progress, including the status of our BHP transaction, before finishing with a reminder of our financial frame and guidance for next quarter and the full year.

We'll then take time to answer your questions.

Looking at the macro environment.

With the oil market in a more balanced position, OECD commercial stocks have declined to below the 5-year rolling average.

U.S. crude and product stocks, which account for around 40% of total OECD inventory, have reduced significantly over the last year to the middle of the range.

With lower stock levels, the oil price remains volatile to any uncertainties, particularly around supply and geopolitics.

Recent factors include the impact of U.S. sanctions on Iranian exports, supply disruption from Venezuela, together with production uncertainty from Libya and levels of spare capacity within OPEC.

In the U.S., infrastructure constraints, particularly in the Permian, have slowed tight oil growth.

These uncertainties could persist well into the first half of next year, supporting wider Midland crude differentials.

Similarly, pipeline and rail constraints affecting the movements of Canadian heavy crude between Alberta and the U.S. are driving wider WTI-WCS differentials, which are expected to be sustained over the coming months.

In gas markets, low levels of storage capacity in the U.S. have driven Henry Hub prices closer to $3.30 for the first time in more than 6 months.

In summary, the oil price outlook has strengthened.

We expect the oil market to remain volatile in the near term, characterized by lower stock levels and ongoing geopolitical factors.

Looking further out, we expect current supply concerns to ease and continued robust demand growth to be matched by growth in the U.S. tight oil production and additional supply from non-OPEC countries.

Turning now to highlights from the quarter.

Underlying replacement cost profit for the third quarter was $3.8 billion, more than double that of a year earlier and 35% higher than last quarter in a very similar price environment.

This also drove strong underlying operating cash flow of $6.6 billion in the quarter, including a working capital build of $700 million.

In the Upstream, our continuing focus on safe and reliable operations saw underlying production increase 7% relative to the same quarter a year ago, driven by the ongoing ramp-up of our major projects.

Building operational momentum, coupled with a stronger oil price, delivered Upstream underlying pretax earnings of $4 billion in the quarter.

We also expect another strong quarterly contribution through our shareholding in Rosneft with underlying post-tax profit estimated at $900 million.

The Downstream reported underlying pretax earnings of $2.1 billion in the quarter.

This reflected a stronger supply and trading result than last quarter and was further supported by high refining and petrochemical availability and retail performance.

Looking further out, we remain focused on delivering our strategic plan and maintaining a strong and disciplined financial frame.

In the Upstream, we saw the recent start-up of 2 further major projects in the Gulf of Mexico with the BP-operated Thunder Horse Northwest expansion and on the Australian North West Shelf with the start-up of Western Flank B, both ahead of schedule and under budget.

In the Downstream, we continue with the growth of our retail convenience partnership model and have now rolled it out to around 1,300 sites across our network.

And as I'll discuss in a bit more detail shortly, we have made good progress towards completing the acquisition of BHP's Permian, Eagle Ford and Haynesville unconventional assets and expect to close the transaction tomorrow.

As we approach the end of 2018, we have strong momentum across the business and are building a tangible track record of operational performance and strong financial results that underpin the delivery of our strategy.

Now looking to prices during the third quarter, Brent crude averaged $75 per barrel, similar to the second quarter average of $74 per barrel.

Prices rose sharply through September, reflecting a reduction in Iranian exports and concern over the level of OPEC's spare capacity.

U.S. Henry Hub gas prices averaged $2.90 versus $2.80 in the second quarter.

And BP's global refining marker margin averaged $14.70 per barrel, slightly below the average for the second quarter of $14.90 per barrel.

Moving to our results.

BP's third quarter underlying replacement cost profit increased to $3.8 billion compared to $1.9 billion a year ago and $2.8 billion in the second quarter of this year.

Compared to a year ago, the result benefits from significantly higher Upstream liquids and gas realizations, higher production from major project ramp-ups and an increased contribution from Rosneft.

In the Downstream, the benefits of higher crude differentials are more than offset by lower industry refining margins and higher turnaround activity.

Compared to the second quarter, the result benefits from higher Upstream liquids and gas realizations, a stronger supply and trading result and an increased contribution from Rosneft.

It also benefits from strong operational performance in refining and petrochemicals, higher fuels marketing performance and a lower effective tax rate.

The third quarter dividend payable in the fourth quarter remains unchanged at $0.1025 per ordinary share.

Turning to cash flow and our sources and uses of cash.

Excluding oil spill-related outgoings, underlying operating cash flow was $19 billion for the first 9 months, of which $6.6 billion was generated in the third quarter.

This included a working capital build of $1.1 billion for the first 9 months, of which $700 million was in the third quarter.

Organic capital expenditure was $3.7 billion in the third quarter and $10.7 billion for the first 9 months of 2018.

Our organic free cash flow surplus was $3 billion in the first 9 months of 2018.

Turning to inorganic cash flows.

In the first 9 months of 2018, divestments and other proceeds totaled $400 million.

We made post-tax Gulf of Mexico payments of $2.9 billion and inorganic capital expenditure was $1.5 billion, including an initial deposit paid to BHP of $525 million.

And gearing at the end of the third quarter was down to 27.5%.

We have also remained active in our share buyback program and bought back 48 million ordinary shares in the first 9 months of 2018 at a cost of $340 million.

Now to operational delivery where we continue to make good progress.

In the Upstream, our focus on quality execution is delivering strong operating performance with operating plant reliability at 96% so far this year.

We continue with the delivery of major projects, successfully starting up 2 most recent projects ahead of plan.

The Thunder Horse Northwest expansion project in the Gulf of Mexico came online 4 months ahead of schedule and 15% under budget.

The project, which achieved first oil 16 months after sanction, comprises a new subsea manifold and 2 wells tied back to the existing Thunder Horse platform.

This has brought forward valuable barrels and demonstrates our strategy in action of growing advantaged oil.

The Western Flank B project in Australia came online under budget and well ahead of its scheduled 2019 start-up.

The project consists of an 8-well subsea tieback to the existing Goodwyn A platform.

So far this year, we've delivered 5 major projects.

Our remaining operated projects, Clair Ridge in the North Sea, which is in the final stages of commissioning, and the next phase of West Nile Delta in Egypt remain on track for start-up in the fourth quarter.

In September, BP accessed new acreage in the prolific Santos basin offshore Brazil by winning the license for the Pau Brasil block.

This represents BP's first operator position in the Santos basin.

In the Downstream, we continue to make good strategic progress.

In manufacturing, Solomon refining availability for the quarter stood at more than 96%, the highest in 15 years.

And Petrochemicals earnings were the highest since third quarter 2011.

In fuels marketing, we continue to grow retail volumes and roll out our convenience partnership model, which is now in around 1,300 sites across the network.

In Mexico, we now have more than 370 BP-branded sites.

And we continue to look for ways to provide lower carbon products to our customers and reduce emissions in our operations.

The Air BP business recently entered into an innovative collaboration with Neste, a leading renewables products producer, to secure and promote the supply of sustainable aviation fuel.

And our Lingen refinery in Germany recorded a world-first, piloting the use of green hydrogen in the production of fuel.

Before I turn to our guidance and outlook, let me take a few minutes to update you on the status of the BHP transaction announced on the 26th of July.

The acquisition of BHP's assets in the liquids-rich Permian-Delaware basin and the 2 premium positions in the Eagle Ford and Haynesville basin, transforms our position as a Lower 48 producer.

The transaction is expected to create significant value through the combination of a world-class portfolio of oil and gas assets with BP's competitive Lower 48 operating model.

Through the sources of value identified, this deal will be accretive to earnings and cash flow per share post-integration.

It is also leveraged to price upside, which we are benefiting from at the moment, above the $55 per barrel WTI price assumption that underpin the purchase price.

Over the past couple of months, the team has been working closely with BHP and we expect to close the transaction tomorrow.

On completion, we will make a cash payment of 50% of the $10.5 billion consideration less the deposit of $525 million paid in July and less customary completion adjustments.

When the transaction was first announced, our intent was to fund the total consideration through a combination of cash and equity.

The 50% cash payment was due on completion with the remainder deferred and payable over 6 equal monthly installments funded through the issuance of equity over the same period.

An additional $5 billion to $6 billion of divestments were expected to fund up to an equivalent level of share buybacks to offset the equity issuance.

Since we announced the deal in July, oil prices have strengthened and our businesses have continued to deliver strong underlying cash flow within a disciplined capital frame.

Our cash cover ratios also remain strong.

Taken together and assuming oil prices stay firm around today's levels, we would now expect to finance the remaining deferred installments using available cash.

This simplifies the transaction, removing the equity issuance and the related dilution and friction costs that would have arisen.

In this case, proceeds from the additional $5 billion to $6 billion divestment program will be used to reduce debt given we would no longer be issuing equity.

Our commitment to fully accommodate this transaction within our existing financial framework remains unchanged.

A full cash transaction may move gearing to the top end of and potentially temporarily above our 20% to 30% band in early 2019.

We would then expect gearing to move back down towards the middle of the band by the end of 2019, in line with the generation of free cash flow and receipt of disposal proceeds.

We will continue to focus our existing share buyback program on offsetting dilution from the scrip dividend over time.

As stated when we restarted this program at the end of 2017, the pace and shape of these buybacks will reflect the ongoing judgment around several factors and may not necessarily match the dilution on a quarterly basis.

However, assuming the BHP transaction is funded using cash, we would now expect to fully offset the impact of scrip dilution since the third quarter of 2017 by the end of next year.

We continue to expect to accommodate the acquisition within our medium-term organic capital frame of $15 billion to $17 billion, and our guidance on returns remain unchanged.

Before I summarize and as we look ahead, let me remind you of our guidance for the full year and the fourth quarter.

For the full year, we expect organic capital expenditure to be around $15 billion.

Divestment and other proceeds in 2018 are expected to be over $3 billion.

As noted in the second quarter, this excludes proceeds from the divestment package we announced with the BHP transaction.

The total DD&A charge is now expected to be around the same level as 2017.

Gulf of Mexico oil spill payments are expected to be just over $3 billion for the year.

And our balance sheet remains strong and we expect gearing to remain within the 20% to 30% band in 2018.

In other business and corporate, the underlying quarterly charge is expected to average around $350 million.

And finally, in the current environment, the underlying effective tax rate is now expected to be lower than 40%, reflecting an increase in equity-accounted income from Rosneft and other portfolio mix effects.

Looking specifically at the fourth quarter, we expect Upstream reported production to be higher than the third quarter with the addition of BHP assets in the U.S. Lower 48.

In the Downstream, we expect lower industry refining margins and we also expect higher levels of turnaround driven by activity at our Whiting refinery in the United States.

Let me summarize.

With delivery of another set of strong operational and financial results, we approach the end of the year as we started it: with momentum and a clear focus on the disciplined execution of the strategy we laid out almost 2 years ago.

Across the businesses, we remain focused on safe and reliable operations with high levels of availability and reliability enabling us to capture the benefits of an improving price environment this year.

We're also making tangible progress across the Upstream and Downstream in delivering our strategic milestones.

We are near completion of the BHP transaction, have recently started up 2 major projects in the Gulf of Mexico and Australia and continue to grow our fuel retail network notably in Mexico.

This is all feeding through to strong underlying growth in earnings and operating cash flow.

We continue to expect the organic cash breakeven of the group to average around $50 per barrel on a full dividend basis in 2018.

As we laid out last year, operating cash flow is expected to continue to grow at an oil price of $55 per barrel real, and together with the continuing focus on capital discipline, to drive growing free cash flow.

Taken together, all of this supports our commitment to growing distributions over the long term as evidenced by the dividend increase we announced in the second quarter as well as our ongoing share buyback program.

It also creates optionality for us to high grade our portfolio as seen with our recent BHP transaction, enabling us to drive competitive and improving returns across the business.

We are looking forward to seeing many of you at our Upstream investor event in Oman, where we will go into a lot more detail on strategic progress and the future opportunities in the Upstream.

Thank you for listening, and with that, we'll now hand over to questions.

(Operator Instructions)

Okay.

Thank you again, everybody, for listening.

We're going to turn to questions then.

(Operator Instructions) And we are going to take the first question from Christyan Malek at JPMorgan.

Christyan?

Two questions.

First, while we welcome a fully cash-funded transaction of BHP, the only caveat I'd sort of highlight is that this revised frame arguably makes you more implicitly long-willed by virtue of seeking to secure $5 billion to $6 billion of divestments in order to reduce debt.

In your press release, you also say assuming oil prices remain firm, expect to fund the deferred consideration with available cash rather than issuing equity.

So first question is, [can you really] risk if oil prices continue to be volatile?

Is it fair to say that you'd allow your gearing to run materially over the top end of your band and you then -- if oil does move lower?

And second question is shifting perhaps to more half glass full.

I'd like to understand the scope enhanced total shareholder return in 2019, I know you talked about it, Brian, on your introduction.

Is it likely to be triggered through sort of target quantum of debt reduction, first as you mentioned your expectation to move towards the middle of the band by end 2019?

So just a part of that upside would be very interesting.

Okay.

Thanks, Christyan.

So I think the way to characterize it is we had the option when we announced the deal at the beginning of July to do this on an all-cash basis or on the basis of 50% shares, 50% cash, and what we've come out and said today is that we will now look to do that on an all-cash basis.

It's a much simpler transaction than we would have expected in terms of having to issue shares.

And what that will create is much lower costs in terms of the final transaction value.

I think the chances or probability of a major oil price correction, which is probably what we'd need to see for gearing to go significantly above the 30%, I think, right now, it's not clear it will breach through 30% next year depending where the absolute oil price is.

And I think it's probably worth just picking up, given oil price stock levels, and it's been 4 months since we announced the transaction, given oil price stock levels have now drifted down towards below the 5-year average, oil is now more prone to oil price movements and potential oil price major movements in either direction.

So I think you could see plus or minus $5, plus or minus $10.

It feels pretty firm right now.

I think we saw it get ahead of itself through this quarter, particularly ahead of the Iran sanctions as we saw Iranian oil come off the market relatively quickly.

We're starting to see some of that oil actually flow whether it be into tank or into storage or domestically within Iran.

But OPEC is sitting where it was vis-a-vis their quotas back in June.

So I think it's unlikely we're going to see a major correction.

You'd have to see a fairly significant correction.

And for this year, we think by the end of this year, we will be balanced at around $50 a barrel.

That will naturally go to $35 to $40 a barrel on a point forward basis.

And so I don't think there's a concern of it going majorly above 30%.

It may drift to the top end of the band through the first and second quarter with the payments, but I don't think it will go beyond that.

And then in terms of gearing, as a objective, if that's not an objective itself, it will just naturally drift down.

Now that we've said we will reposition the divestments now to pay down debt, we will start to do that going forward.

So frankly, it will -- it will naturally drift towards the middle part of the band at around about $70 a barrel, assuming that's where we are for next year.

But we won't actually set the plan for next year until January time.

So January -- so not -- so your discussion around buyback would have to be approved around the sort of January-February time as opposed to before year-end.

Buybacks -- what we've also said with this is the scrip buyback program was always meant to be built over time and therefore would take some time.

So for this year coming into 2019, we have committed to make sure that all the scrip is repurchased by the end of the year.

We would've had the strange position through the fourth and first quarter where we'd be issuing stock and buying back scrip dividend, which would all have been counterintuitive, not really make a lot of sense.

So we'll probably slow down our scrip uptake through the first half of next year, but look to offset everything we've issued since the fourth quarter of 2017 by the end of next year.

Okay.

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

Irene?

I had 2 questions.

First, Brian, you referred in your prepared remarks to the oil market, oil price volatility.

I believe Bob was recently quoted in an interview saying that in your project sort of investment appraisal process, you now tend to use $60 to $65 and $50 to $55.

Was just wondering if you can elaborate on that topic.

Then, secondly, Upstream unit production costs, up a little bit, 1.5% in the 9 months.

I wonder if you can please share your expectations for that metric in 2019 as you incorporate BHP and if prices remain where they are.

Thanks, Irene.

And maybe I'll come back to the question of $60, $65 in Bob's recent comments because I've received a lot of questions about that this morning, so I think I'll just take this opportunity to clarify what Bob was talking about in terms of the Oil & Money gas conference and the $60, $65.

In terms of unit production cost, it's very simple, why you've seen a slight uptick.

One is we had a big maintenance schedule through 3Q, which we typically do 2Q and 3Q in the Upstream.

And also, obviously, with the higher oil prices, you start to get PSA effects come through the volumetric measures, which therefore reduces the denominator.

So as oil prices go higher, that volume number comes down, so you will see a little bit of movement around that.

But the overall trend is still in the same direction, which is downward.

And a lot of that's being driven by technology, and another number of things that actually Bernard will take you through in a lot more detail at our Investor Day in December.

So we'll go into it a bit more granularity around that, but the overall trend is still down.

In terms of $60, $65, I think Bob was talking about -- so we run basically 2 or 3 numbers, but the ones that we're really focused on in our investment case is $50 a barrel and $75 a barrel, and I think basically where Bob was basically describing where the middle of that range is.

I think he was actually referring -- coming into this year we normally set our plan, our oil price for a 12-month period, which just helps us manage the cash flows within that 12-month period.

This year, we set that at $55.

A few weeks or months ago, we may have thought about what oil price was set for next year, something around $60 to $65 seems like a conservative number that we could start to plan on that basis.

But the $60, $65 does not reference anything around specific investments that we're making.

We run those cases at $50 and $75 a barrel and it's $75 a barrel real over a long period of time and $50 is the sort of base case that we run everything at and that's how we look at our projects.

Okay.

Thanks, Irene.

We'll take the next question from Jason Kenney at Santander.

This is Jason, Santander.

Just looking at your indicator sensitivity and I'm wondering where the Downstream indicator, I think it's $500 million operating profit per $1 per barrel refining indicator.

I'm just trying to see how that reflects the widening crude discounts that you can get in Canada.

I know they're not necessarily specifically Downstream or Upstream, but just trying to gauge if we can get a better sensitivity idea quarter to quarter or even year to year on those guidance, for 2019 in particular?

Yes, that's tough to do.

But what we have done is -- so in terms of guidance, but you have to remember, John -- Jason, within any particular quarter, there's an awful lot of moving parts across the business.

And so therefore, the rules of thumb are really designed for in a stable price environment, so an oil price of X that doesn't move by more than a few dollars within that year, then you could reasonably use these rules of thumb.

When the oil price sort of goes from $50 to $80 a barrel, it's really difficult to use those rules of thumb.

You're not going to get a perfect dollar-for-dollar move on those rules.

That also applies in the refining space.

We have seen huge differentials between Canadian heavy and WTI, up to $40, $45 a barrel so far this year.

They look like they're sort of set in terms of what we're expecting going forward.

We'd still expect a differential certainly through this quarter and into next year higher than the average that we've seen over the last 2 or 3 years.

You also have to then take into account the fact that, of course, we have apportionments on the pipeline, so we can't always run 100% heavy crude out of Canada and that apportionment, even in October, which is all in the public domain, we were constrained and we had certainly could access only 43% in October, 45% in November.

And that's all about recovery of syn crude production.

So it's pretty hard to give you a rule of thumb around that.

But needless to say, the Whiting investment was done at sort of mid-teens in terms of the assumptions around heavy versus WTI.

So something around $14, $15, $16 is what we'd assumed in the economics back when the oil price was down at sort of $50, $60.

We're seeing differentials significantly higher than that, but we have no specific rule of thumb that we can give you other than the sort of raw calculation you can do of $1 a barrel across the refining margin may give you certain uplift, and I think people are trying to come up with estimates of that in the past.

But we have nothing that we can sort of stand behind as a rule of thumb because there are so many other moving parts in the slate of the refinery and what the products look like to really give you anything, which would be helpful in terms of those calculations.

Okay, I mean, it is a great result in the third quarter.

Do you think the fourth quarter could be similarly stunning?

No, I think third quarter in Downstream, you had supply and trading coming back to an average quarter from what was a small loss in the second quarter.

And you had high availability, which allowed us to capture those higher refining margins.

So really, it's about -- if the kit is working -- remember, we're right in the middle of the turnaround with Whiting today, if the kit is back running at the sort of levels we saw in the third quarter, but I think sustaining 96% availability from my humble experience of refining and marketing over 30-odd years, that's a pretty tough measure to sustain.

The guys will try and do that through the fourth quarter, but I don't think you necessarily see that repeat into the fourth quarter.

I think, Jason, just to add to what Brian said as well, we obviously talked in the second quarter about the Whiting refinery being a 7-week turnaround.

That kicked off around the middle of September, so clearly is weighted more towards a fourth quarter event.

So in terms of capturing the differential, clearly, the team there works hard to do so.

But there's a heavy weighting in that turnaround in the fourth quarter, expected probably to end around mid- to end of November.

Okay.

Next question from Michele Della Vigna, at Goldman Sachs.

Michele?

Congratulations on the strong result.

I was wondering whether the improved tax guidance for this year to below 40% is sustainable in the coming years as well in a similar oil price environment.

And secondly, I was wondering if you could give us an update on the remaining Macondo business and economic loss claims.

Yes, well, so Michele, tax, we'd said this year over 40%.

We've steadily moved that down.

Now we're saying below 40%.

It is purely a function of the portfolio mix that we have today.

And as we get stronger earnings out of Rosneft, because those earnings come through on a post-tax basis, that will reduce the overall underlying effective tax rate.

So obviously, the higher the Rosneft number, that will weigh down -- that will be a contributing factor towards a lower effective tax rate.

But it's really about mix and the mix of the barrels and where the production is coming from.

We haven't set guidance yet for next year.

We'll go through and do a portfolio assessment.

We'll look at an oil price planning assumption for the 12-month period for next year and then we'll come up with the tax rate.

I don't think it's going to be wildly different from the 40%.

We're probably going to be still over 40% for next year, but we'll come back with guidance on that at part of 4Q results.

And then, on Macondo, in terms of the liabilities, we are down to the final series of claims.

The majority -- I mean, the vast majority, which have now been processed, but there is a process with the Plaintiffs' Steering Committee Court Supervised Settlement fund that allows claimants that have been denied to resubmit and they will be in either 1, 2 or the third cycle of resubmissions.

But we're now in the sort of de minimis.

And this is probably one of the quietest quarters that we've had around Macondo.

BEL claims for this quarter, I think around about $50 million is what we've taken through in terms of provision, but we are in the final sort of -- I could say 22 claims, but then there's a recycle effect that takes that number to 200.

But there's a series of claims that have been denied and get recycled in the system under the original settlements.

But we're sort of in the de minimis end legal game now of whatever is now left on appeal and then we'll fight those appeals through the Fifth Circuit and the courts of justice appropriately going forward, which is what we have been doing up to this point in time.

Okay, Michele.

Thanks.

We'll move next to Lydia Rainforth at Barclays.

Lydia?

Two questions, if I could, the first one on the Upstream side.

Given sort of what was pretty flat production quarter-on-quarter and pretty flat prices, there was quite a big uplift in the profit there.

Can you just talk through a little bit more detail around the drivers behind that?

And then the second one just on the divestments, it has seemed relatively quiet on the divestment front.

And so just wondering what sort of confidence you can give us around that $5 billion to $6 billion and should we think about it being more back-end loaded towards next year?

On the $5 billion to $6 billion, great.

Thanks, Lydia.

In terms of looking at Upstream earnings and what was driving it, the majority piece of this was actually obviously off the back of the oil price as realizations and it's realizations more than price improved is a big lion's share of what we've seen come through.

But something around about the same sort of level, but just below that is higher sales volumes, particular coming out of Angola and the North Sea, have been the big drivers.

Because obviously at these higher prices, some of those regimes, particularly in the North Sea, highly leveraged to earnings at the higher price.

So that's the basic driver.

But it's basically, one, high reliability.

We were up over 95% for Upstream across the piece this quarter.

We had the production growth coming through underlying this quarter 7%, 6.8%, and underlying production growth now for the year of about 10%.

So Bernard and the team are delivering against what they said they were going to be delivering against.

And we have the extra benefit this year particularly Thunder Horse and Western Flank B coming onstream ahead of where we had them planned for next year and significantly below budget.

So I think all of those things have helped with the momentum that you've seen come through that earnings.

But I think it's really about having the kit running reliably has allowed us to capture those higher prices and get those stronger netbacks.

On divestments in terms of this year's program of over $3 billion, it is completely back-end loaded this year as it was last year.

And you'll recall last year, I think the divestment proceeds were around about $4.5 billion with $3.5 billion coming through in the fourth quarter.

It's going to be similar this year.

I think so far year-to-date, we're around $0.4 billion, $0.5 billion in the first 3 quarters.

We will still deliver -- we expect to deliver over $3 billion by the end of the year.

It's all going to be sort of 4Q is when they will come just like last year.

And then the $5 billion to $6 billion program is predominantly Lower 48.

We've certainly announced internally with the teams what those assets look like.

A lot of the legacy historic assets we had, quite gassy in nature across the piece.

But on all cases, we feel that we have a pretty -- we're confident in terms of the potential buyer spectrum we have availability out there, I mean, especially given this particular basin.

So we're confident about getting those away and we'd expect the first tranche of those away next year and we would not expect them to necessarily, with this particular tranche, be back-end loaded.

I mean, we've had time to get these ready.

We've got the data rooms prepared.

We're going out to market.

So we'd anticipate that you'd start to see the first tranche of those divestments done next year.

They may well be at the end of the year, but I suspect they'll be -- coming into this year, we knew it was going to be back-end loaded.

We sort of told you that at the start of the year.

In this case, I think we'll see what the market looks like as we get out to the market on the $5 billion to $6 billion.

And the first tranche -- it won't be $5 billion to $6 billion next year, it will be over a 2- to 3-year period.

But the first tranche we expect to get away next year and we will be able to let you know how that goes probably into the second quarter, third quarter next year.

Okay, thanks, Lydia.

We'll go to Thomas Adolff at Crédit Suisse next.

Thomas?

Congrats on the strong results as well.

Two questions for me.

Firstly, on your CapEx guidance, now I'm quoting one of your peers.

Equinox said $11 billion is a good medium-term number based on today's cost index, and if you go beyond that, it would overstretch the organization, an impact on project execution.

So I wonder, in the case of BP, would you say if you go above $17 billion, it would overstretch the organization?

I know you want to stay in the $15 billion to $17 billion range, but I wanted to understand whether that's also the sweet spot organizationally.

And then, secondly, in terms of LNG and FIDs, I wonder if you could give an update on Tortue FLNG.

What's still missing?

Will BP be the sole offtaker?

Has the development plan been approved?

And what -- when exactly do you expect to take FID?

Great.

Thank you, Thomas.

And so what I would describe in terms of the $15 billion to $17 billion is that is a range which has a huge amount of flex -- about $2 billion is a huge amount of money in terms of flexibility of what we can do.

And certainly, as we've seen deflation continue to come through this year, surprisingly so given where oil prices are, we are still seeing, I think, technology driving a lot of deflation.

But we're now saying $15 billion for this year.

I think at the start of the year, we were expecting it to be closer to the middle part of that range of $15 billion to $17 billion.

So we're down at $15 billion.

We have a huge amount of capacity that Bernard and his team have created, particularly in the Upstream, to absorb BHP and be able to ramp their drilling program up as we go into next year.

And we're going to start that process in the fourth quarter, probably around Eagle Ford and maybe just touching Permian, but we're not settled on that yet, but certainly in terms of Eagle Ford.

So I think we have flexibility within the program.

What -- in terms of the organization, the size of the organization, we moved to a central projects group many years ago back in 2009.

That has really come to fruition the last 3 or 4 years as Bernard's got that team humming in terms of rhythm.

And I would describe a rhythm that you start to get into with an organization that it gets into a rhythm of delivering projects every 6 to 9 months, then coming onstream.

You learn from all the things that you learned from the previous project and you take those learnings and move it on to the next project rather than a sort of stop-start or a deployed organization where you're having to relearn the things going forward.

And I think that's why you're seeing the advancements of Thunder Horse this year, Western Flank B, why those projects have come onstream earlier is really about understanding the rhythm of what we've learned from other projects.

So I wouldn't necessarily describe the capacity of our organization around a specific capital number.

It's more about activity.

And last year, I think Bernard was on record as saying for last year, I think we got up to the most hours we've ever deployed in any 1 year on the series of projects we have that came onstream last year.

We were probably at the top end of comfort in terms of bringing those projects on, which the team did a phenomenal job of doing.

So we're pretty comfortable where we are today.

We're in that rhythm of bringing projects on and we will sort of see how that progresses going forward.

But we're not sort of in a place where we're going to move off the $15 billion to $17 billion band right now, so it's a bit of a moot point.

And just to reiterate, we will bring the BHP transaction in and we will live within the $15 billion to $17 billion frame and that will allow us to ramp capital up in the Lower 48 where it's the one place where you can ramp activity up quickly as [apparently] from what we've learned from our own business of running our old legacy assets.

In terms of the Tortue project, the project entered its feed in April 2018 and we're still targeting FID by the end of '18 and first gas in 2022.

The project was targeting a first phase of about 2.5 million tonnes per annum and then we've got further 2 phases to test it to a further 10 million tonnes per annum.

We've got nothing left to update on that.

We still expect FID this year.

And I'm sure Bernard will have some more to talk about that in December at the Investor Day in Oman.

Okay.

Thanks, Thomas.

Yes, let's go to Rob West at Redburn next, please.

Rob?

I'd like to start on production.

I don't know where other people were in the quarter, but the production number was a little bit below what I had in, flat year-on-year.

And really, Brian, I'd be interested if you could sort of [check] some exuberance -- results from that because I'm looking at the trajectory of growth that's still to come, so ramping Shah Deniz further, the start-ups like Clair and West Nile Delta.

And I'm wondering, should I look at this quarter as base -- you're actually getting quite a lot of growth from that baseline?

Or should I look at -- is there something in this quarter that is a negative in terms of the production that might continue going forward?

So that was the first question.

And the second one is just I'd just like to go back to the timing of divestments, the $3 billion that you've alluded to in your comments this morning.

I think, so far, year-to-date, the run rate of divestments coming through, it's under $500 million.

And so my question is just in terms of the settlement of that $3 billion, could you just say how much more of that is expected this year?

Or is it just announcing the transactions that you're aiming to do before year-end?

Yes, let me just pick up the second part of that question because it's fairly straightforward.

Just like last year, we will announce -- basically, effectively last year, we had $4.5 billion of disposals.

$3.5 billion of proceeds came in the fourth quarter.

We'll have exactly the same this year, wouldn't be that level, but it will be -- overall, it will be over $3 billion for the year, which is what we've indicated.

We will still expect to be over $3 billion and we'll be looking to close a series of transactions in the fourth quarter that will get us over that figure.

So that's pretty well underpinned.

And we did say at the start of this year it's a mirror of last year, precisely the same.

We said it would be back-end loaded.

It is back-end loaded and so there's no changes in terms of that.

So it's exactly the same pattern that you saw last year.

Then in terms of this...

That's firm?

I said we still expect, I can't be firm, firm because that'll be giving you guidance, which I wouldn't be able to do because it's a function of closing transactions.

But we have indicated in all of our material today that we still expect to be over $3 billion for the year.

If we didn't think we could deliver in the fourth quarter, we would've told you that.

So it's not -- but I can't be firm, firm because it's a function of whatever gets announced through the fourth quarter and gets closed.

So things can always slip into January, that's always possible.

But right now our expectation is we will have over $3 billion of divestments by the end of this year.

Then in terms of production, I think maybe if you go back to the guidance and what we've told you before, if you take out the portfolio impacts of ADNOC, PAE -- the sort of PAE transaction true-up and AGT, so you take those things out, the ADNOC concession, which was in there last year, but wasn't there this year, it's significantly over 100,000 barrels a day of production that we had last year that we no longer have because it's no longer in the portfolio.

So if you actually adjust for that, I think you'll see close to 7% underlying growth this quarter.

And then we've signaled to you for 4Q is that BHP transaction comes in, that will be additional portfolio volume that will come into the mix.

So actually, we're seeing on an underlying basis, if you strip out the portfolio that's been divested or has come out of the base business, actually quite significant growth this year to the tune of about 10% underlying year-to-date.

Okay, Rob, thanks for the question.

We will next go to Alastair Syme at Citi.

Alastair?

Can you just -- Brian, can you just update on the impact of IFRS 16 as you see it?

And will you revise the gearing band or will you look to absorb it?

And secondly, can you maybe give us a little bit of an update on the roadmap around the Downstream free cash target towards $9 billion to $10 billion by 2021?

If I'm right, we're running at about $6 billion over the trailing 12 months.

Great.

Thanks, Alastair.

So on IFRS 16, there will be an awful lot of moving parts associated with that particular accounting standard.

And I think while it was intended as a standard to give clarity around sort of the extended debt book, of course, it will move pretty much a lot of the lines of the P&L and balance sheet as a consequence.

So it's going to be a little bit noisy for you all.

And what we will do at the end of this year as part of 4Q we'll give you a true-up of how it impacts each of the individual lines of the P&L and balance sheet, but it's going to affect a lot.

We will basically present all of the information on the pre-IFRS 16 and post-IFRS 16 basis, so at least you get clean line of sight and transparency on what's moving.

We haven't made any decisions yet whether or not we will end up with a gearing on the old basis, i.e., because it's a non-GAAP measure, we can define it however we think is appropriate in terms of our financial frame.

But probably the most important thing about IFRS 16 in terms of the original intent is our cash cover ratio is unaffected by IFRS 16.

The rating agencies already use extended debt in the calculations of cash cover ratio.

So leases are already part of the extended debt book.

So it will have no impact from a rating agency perspective, but it will create a lot of noise and clunkiness around each of the individual lines of the P&L and balance sheet.

But we'll give you a very clear route map of what that looks like.

And then in terms of -- is that okay, Alastair?

Yes, that's perfect.

And then in terms of the target of $9 billion to $10 billion, I'll wait till we get to the end of this year.

But against that target, I think we are close to $7 billion delivered with a further $2 billion to $3 billion to come, but on track with the targets in the way in which Tufan laid that out to 2021.

Do you think it will be quite linear to 2021, Brian?

Or do you think it will be a step-change?

I think in the current market, what I will guarantee you is it will not come, firstly, along the lines at which we planned it.

That's the one thing we've learned about the last 7 quarters because it will be a function of whatever the (expletive) oil price or other factors are doing at the time.

But that what I think you've seen Tufan and his team create in the Downstream, is a huge amount of resilience to deal with various economic factors that may impact that business.

And I think the biggest one of those was the way in which Tufan and the team have been able to neutralize the volatility of refining margins in their base business.

So we could lay a plan out for you.

We'll guarantee we will not follow the exact quarter-by-quarter trend of that plan.

But I think what Tufan has created is a huge amount of optionality within his portfolio to manage that, and therefore, we have confidence around its delivery.

Can I just clarify, do you think the sort of macro environment, the trailing 12 month is representative of what you've envisaged for 2021 and that target?

No, I think we already know we're in a very different environment because originally the whole environment we set for all the targets is around $55 a barrel real.

Now in the Upstream, we'll take benefits from that in terms of the additional free cash flow we get from where the prices are today.

We've got, I think I mentioned earlier, volumes -- and I know it's a broken record, but volumes are back below the 5-year average or certainly close to the 5-year average both on a macro, global economic basis and within the United States.

So I think, certainly, oil prices are pretty well underpinned above $70 for the next sort of 6-month period or so.

At least we can't see anything which would majorly move those out of kilter with that and there may actually be some movement to the upside, but I think plus or minus $10 a barrel is pretty tough to call it.

By the time we get to 2021, I think there's a lot of things could unwind.

We'll see more production coming on in Lower 48.

You may see some softening of demand, although we're not seeing major demand-side correction at the moment if prices stay very high.

But I think within -- in terms of the Downstream, we're seeing benefits right now, big light -- heavy spreads that we're seeing with Canadian crude coming into the big machine cooled Whiting refinery, which can take up to 320,000 barrels a day of heavy crude.

It's clearly not at those sort of levels given curtailment issues.

So I think what I'd say, Alastair, is look, we've created a portfolio now, which has a huge amount of optionality around that portfolio.

So we're pretty confident with the targets we've laid out for you for 2021.

We just may not end up delivering in the same way that they were originally envisaged back in the start of last year and we're already seeing that through these first 7 quarters.

Okay.

Thanks, Alastair.

We'll next go to Henry Tarr at Berenberg.

Firstly, looking at new FIDs, have there been any changes to the strategy in terms of contracting?

So you're looking to sort of lock in low cost, for example, or do you see sort of no reason to do this today?

And then in terms of the portfolio, assuming that oil prices remain firm, gearing comes lower over the coming quarters, do you have some flexibility there?

Where would you, and maybe this is a longer-dated question, but where would you be looking to add to the portfolio should the opportunity arise?

That's great.

Thank you, Henry.

That's a good question on the optionalities.

So in terms of FIDs, I think we already have 5 this year from memory, which is around, I think, Oman, a couple in North Sea, India and Angola where we've seen 5 FIDs.

I think what the organization has created now with Bernard's leadership and that exec team is a lot of our contracts are long term anyway.

So a lot of our rig contracts will be on a sort of 5-, 7-year basis on a rolling basis, so we've already been able to capture some of those lower rates.

And we're certainly not seeing any inflation on the rig rate side right now.

So I think we will look to contract and procure activity on a central basis across the suite of projects and we'll look to optimize across that piece.

And that's the whole purpose of this sort of central projects group and the central procurement group within Upstream that do those things.

So I think we've already got locked in contractually a lot of activity associated with some of these projects.

So that's sort of point one.

And then in terms of opportunity set, and I think we announced in September we've acquired a license in the Santos basin.

That would be an example of a sort of step-out for us where we do think there's a huge opportunity for us in a country like Brazil where we've seen some major economic reform over -- progressive reform over the last 2 or 3 years.

And we have a great partner there, Petrobras, that we're working with.

So that will be an example of the sort of areas where we'd look to be stepping out and sort of increasing, but within the $15 billion to $17 billion frame that we've already laid out.

And maybe just building on that, you will have seen already this year we've had new access in license rounds in -- I talked about Santos basin; also U.S. Gulf of Mexico, our traditional backyard; Mexico; the North Sea, another one of our traditional backyards; and Azerbaijan.

So -- but that's all within the $15 billion to $17 billion frame.

Okay.

And just one quick follow-up then.

With oil prices where they are now, are you seeing a greater emphasis then on exploration rather than acquiring barrels at this point in the cycle or...

I think it's a mix.

I mean, you always want to be able to find oil with your own drill bit or through exploration.

That's always the primary focus because, ultimately, it will be the lowest-cost way to access resources.

Equally, if you look at what we've just done in Lower 48, I think we've bought a very premium position, which we will definitely enhance value around.

And the more that we see of those assets, we can see that.

So I think it's going to be a mix going forward, but obviously, you'd always like to sort of find oil-discovered resources through the drill bit.

Okay.

Thanks, Henry.

We'll next go to Jon Rigby at UBS.

Jon?

Two quick questions on -- one on disposals.

So if I'm right, I think you count the Conoco transaction as a disposal.

So am I right in thinking that the net cash in through the fourth quarter despite the gross disposal numbers not likely to be that significant?

In which case, am I also right in thinking that disposals next year will be sort of an aggregation of that, that's linked to BHP plus, I guess, you probably want to continue to pursue the $3 billion ongoing disposal plan as well so probably closer to $8 billion to $10 billion for 2019?

And then just, secondly, linked to that, but sort of more philosophically is I think you keep talking about your 20% to 30% band.

But it seems to me that over the last couple of years, BP has been wanting to be opportunistic in making acquisitions of assets and so on.

I'm aware the Abu Dhabi transaction, you issued stock.

This one, you almost did and then have chosen not to because of the complexity and the value and I completely agree with the decision you made on that.

But wouldn't it be better, all things equal, for BP to be running at 20% or lower so that you can do these kind of transactions in a fairly straightforward way?

You just turn over your checkbook and pay for it and go home again.

Yes, on that, I'll pick up the last part of the question.

I think one of the things, Jon, I think we all need to reflect on, it sort of helps a little bit, I think, in terms of catching why we are where we are in that gearing band.

First of all, 10% to 20% gives you a huge amount of flexibility.

So that's a big billion dollar number that you have in terms of flexibility.

We sit towards the top of that band, of course, because unlike other players in this sector, we've had somewhere close -- by the end of this year, we'll be over $14 billion of cash has flowed out as part of the Macondo -- various Macondo settlements.

And that stays with us on a sort of $2 billion next year then $1 billion a year after that, is what we've sort of -- the guidance we've given you.

So if you sort of correct it for that $14 billion, of course, you would be down at the sort of bottom end of the range and so I think you have to recognize that.

We will pursue deals, which are -- will be opportunistic, strategic and we will look at the financial frame and where we are within the financial frame.

The financial frame has given us huge discipline.

Over the last 30 years, we've run with a very similar frame.

It allowed us to manage the $67 billion Macondo liabilities over 2010 to where we are today.

It's allowed us to manage the oil price correction, which we came into with about 13% gearing, if you remember, when the oil price went from $110 down to $28 a barrel.

And it's allowed us to go through that corrective phase.

And it allowed us to actually come out and do the BHP transaction.

And when we announced it at the beginning of July, we've now had 4 months of oil prices in a much firmer bandwidth.

So one is 30% gearing is not that large a number for a company of our size and scale.

It will naturally come down, but not because we're targeting it to come down, it will naturally come done within the frame we've set because we've got capital set at $15 billion to $17 billion.

We know about the $5 billion to $6 billion disposals around BHP.

So think of that as being $10.5 billion going out to acquire those assets, premium positions, and then $5 billion to $6 billion coming back in so it's only really a net $5 billion transaction for the company.

And then when you think about it in those terms, then the gearing can go up and it will naturally drift back down to the middle part of the band.

As oil prices stay up over $50 a barrel, we will be surplus free cash as we go into 2020 and 2021.

And of course, we've said our breakeven goes down to $35 to $40 by the end of 2021 unless we choose to distribute to shareholders.

And you saw the signal that we did again within the financial frame to be able to increase the dividend in the second quarter by $0.0025.

So we can have an objective function on gearing right now.

It will naturally come down within the frame that we've set and we've been able to absorb a gross $10.5 billion or net $5 billion transaction in the middle of all of that.

So I think that's the way we sort of think about it.

But I agree with you, clearly, the lower yield gearing, that creates more, I think your word's, firepower, to do potential other things, but we're pretty happy with the portfolio we've got.

I think BHP is a huge opportunity for us in terms of access in those premium positions.

On the disposal proceeds, yes, it does include the Conoco swap that we talked about, which will -- should close in the fourth quarter.

And then of course, there are proceeds, cash proceeds over and above that transaction.

We do have 1 deal, which was relatively significant, will likely now slip into the first quarter of next year.

So when we set the targets of over $3 billion, the total packages that we were looking out were significantly above $3 billion.

But right now, we are still confident that we'll deliver over $3 billion by the end of the year.

In terms of next year, we haven't actually set a target yet, but you should assume for next year it will be a tranche of the $5 billion to $6 billion plus the usual $2 billion to $3 billion churn that we have every year within the portfolio.

Okay.

Thanks, Jon.

We'll go to Lucas Herrmann at Deutsche Bank next.

A couple of project questions if I -- or one project question, if I might, and then just a further question on Whiting.

Brian, I just thought if you could update on Shah Deniz and how the production profile and the ramp is going.

And similarly, Clair, how you expect the ramp to proceed as we go into 2018.

And secondly, on Whiting, just conscious that in 2014, '15, last time Whiting was down, the impact on quarterly results in the Americas business was pretty significant and pretty disappointing.

I'm not expecting disappointment again, but I just wonder whether you can give us some better indication of the contribution that you expect Whiting's downtime to see you cede, that wasn't the best phrase.

Okay, I'll...

How much might you give up from -- how much might Whiting give up relative to a normal quarter?

What should we be expecting rather than being shocked?

I think that'll be really difficult, Lucas, but I think I'll pass that question to Craig.

I'll talk about projects.

Shah Deniz start-up ended -- basically we started up end of June 2018.

I think Bernard's taken you through this before, but 26 development wells, we have 2 offshore platforms, we have about 500 kilometers from memory of subsea pipelines.

The Sangachal onshore processing and compression facilities are all new.

And of course, that gives the big expansion to the South Caucasus Pipeline.

Total peak production is expected to be 310,000 barrels a day, and everything is going well with that project as far as I know and you'll get a lot more detail on that in December when Bernard takes you through where we are with this year's project suite and what the future looks like.

Clair Ridge, we're still on track for 4Q.

We are almost complete and ready to commission.

We've got new facilities.

We have 2 bridge-linked platforms on that development.

It's a completely new development with some brownfield modifications around the original Clair Phase 1 and the Sullom Voe Terminal.

It will have 110,000 barrels of peak production.

But we're right into the sort of winter now in the North Sea, so I don't think there are any guarantees.

We expect it to start up in the fourth quarter of 2018.

But as we get into the sort of weather patterns of the North Sea between now and the end of the year, I really couldn't say and we couldn't call it that closely.

But right now, all things being equal, we'd expect it to come onstream in the fourth quarter, weather permitting.

Craig, on Whiting, I've got no idea what sort of guidance and I'd guide you as to giving anything specific in the way of numbers, but at least you could talk around the turnarounds, at least give a sense of the amount of weeks it will be out.

Yes, so just repeating a little bit of what we talked about earlier.

So the Whiting turnaround started around the middle of September.

It's forecast to go through to around the middle of November.

If you remember, Lucas, Whiting has around 400,000 barrels a day of capacity.

It can run up to and probably slightly above 80% heavy crude.

You've seen the heavy crude differentials this quarter running at around $24 a barrel and actually spot-wise higher than that, but obviously apportioned according to Enbridge Pipeline nominations.

So I think it's a matter of getting your calculator out, Lucas, and probably doing a bit of back-of-the-envelope stuff.

But it is a significant turnaround.

It is for a duration of, let's say, around 6 or 7 weeks.

We're clearly playing into refining marker margin that's leveraged Canadian crude and we're accessing, or rather in the case of the turnaround, limited in terms of access to the differential.

So yes, that's probably about as much as we can say on Whiting, but it will clearly have an impact in fourth quarter.

And Brian, sorry, just coming back to Shah Deniz, could you give any indication of what production was through this quarter?

No, we wouldn't normally give you specifics by asset.

We would normally sort of do that by -- on an asset basis.

But I think you'll get more of a sense of that at the Oman Investor Day in December.

Okay.

Moving towards the end of the questions and penultimate question from Thomas Klein at RBC.

Thomas?

Well, just a quick one for me, thanks, on divestments, which have been discussed a few times.

Just wondering if you'd be willing to sell down your stake in Aker BP to hit your targets given it's performed well since its original formation.

We would definitely not comment on any specific asset, but I equally, while I wouldn't comment, I would say Aker BP has been one of those innovative investments we have made to take what was at the time a late-life asset in terms of our own position, go and join with partners that we trust and know well and we have a long-term relationship with and I think what that has created is a huge amount of value for its shareholder base for BP.

So I could only say positive things about Aker BP, but it certainly wouldn't be, from a personal basis, something that we would look at.

But we never say never with any assets.

But Aker BP, it has been a great investment, but it certainly wouldn't be one that we will be looking to sell.

And actually, to be clear, we don't have any deficit to make up in the disposal program.

We have typically a disposal suite of assets that would be nonstrategic in terms of long-term hold position or things, which we believe would be of more value in the hands of others.

Aker BP wouldn't fall into either of those tests.

So no, we're very happy with the Aker BP investment.

Thank you, Thomas.

And we'll take the last question then from Jason Gammel at Jefferies.

Jason?

I had 2 on Whiting, if I could, please.

You did make reference to this being a pretty major turnaround.

My understanding is that it involves at least the coker and the largest CDU.

So my question is does this leave you well positioned to really not have to do much in terms of taking Whiting down during 2019, 2020 when a high conversion, a high middle distillate yield refinery could be getting some pretty significant advantages from the IMO rules?

And then the second question is you've referenced that you've been under apportionment on delivery of WCS because of the Enbridge line.

Do you have any line of sight into when you might be able to get back to your full nominations?

And if not, is there any potential for using rail to access incremental WCS?

Yes.

So I think on the latter part, as new infrastructure comes in place and new pipelines come in place, those constraint issues that lead to apportionment today will start to ease.

But I don't think that's going to happen in the short term.

That's more of a medium-, long-term remedy.

In terms of the refinery turnaround, it's got the crude unit, the coker unit and the sulfur treatment units are out and they are being done on the usual routine that we'd expect on any maintenance plan.

I'd be very surprised if we're going to come back and redo those again in 2019.

That's highly unlikely because the typical maintenance schedules that we look at are on a 2- to 3- to 5-year basis.

So I don't think that will come back into play next year.

And you're right, that means that we will be geared up and have been geared up and have been now for the last 18 months, 2 years preparing for the new standards that come through in 2019, back end of 2019 which will be a huge opportunity for everybody.

Okay.

Thank you, Jason.

That's the end of the questions.

Let me just maybe hand over to Brian for a couple of closing comments.

Thank you.

Great, thanks, Craig, and thanks for all your patience today and the suite of questions.

And I think this is another -- it's the seventh quarter of the 20-quarter strategy that we laid out for you back at the start of last year.

I think at the heart of everything that you've seen today in terms of the results is safe and reliable operations.

When the operations are safe and reliable, it means that you're able to take advantage of the price environment that you find yourself in and I think we did that through the third quarter and we will continue to focus on that on a point forward basis.

We're looking forward to seeing everybody at the Oman Investor Day.

We have a very big turnout coming for that.

We will give you a little bit more insight on what the future of the company looks like out beyond 2021 and some of the big things going on in the modernization and technology space, which is changing a lot of what we're doing inside the company and is underpinning the results that you saw today.

So with that, we look forward to speaking to you again on the fourth quarter call, and if not, we will see you in Oman.