英國石油 (BP) 2019 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.

Good morning, and welcome to BP's Third Quarter 2019 Results Presentation.

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

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

Before we begin today's presentation, please take a moment to review 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.

Thank you, Craig, and good morning, everyone.

It's been another resilient quarter despite the ongoing market and geopolitical volatility.

Our businesses are performing well, we've delivered a strong set of underlying results, and we are continuing to advance our strategic agenda.

As you'll be aware, the Board announced earlier this month that Bob will retire as CEO, with Bernard taking over following our fourth quarter results in February of next year.

Bob has had an exceptional career over the last 40 years, and his time as CEO has been one of great success.

He has steered us through some of our most turbulent times, including Deepwater Horizon, and rebuilt BP as a stronger, safer company and, most recently, has led the change on the energy transition.

His dedication as CEO and member of the Board earned the respect of not only those at BP but also amongst the wider industry and business community.

It's been a privilege to work alongside him.

And I'm sure I speak on behalf of many both inside and outside BP when I say he will be greatly missed.

Bob -- with Bob's retirement comes a new chapter for BP.

Bernard will take over as CEO and member of the Board, bringing deep experience of the industry and a strong track record as Chief Executive of the Upstream.

I know that he will lead our company with the same level of dedication and focus through what is sure to be a transformational phase for BP.

Turning then to highlights and, first, the financial results.

We reported underlying replacement cost profit for the third quarter of $2.3 billion, coupled with strong underlying operating cash flow of $6.5 billion including $100 million working capital release.

Turning to strategic progress, where we continued to see real momentum.

We continued to actively manage our portfolio for value, focusing our attention on the most competitive opportunities for the group.

Consistent with this, we recently announced the sale of our Alaska business to Hilcorp for $5.6 billion.

This represents the end of a long history in the state, but the proceeds will provide a material contribution towards our target of over $10 billion of divestments and supports the ongoing deleveraging of our balance sheet.

In the Downstream, we continue to progress our fuels marketing growth strategy, agreeing a new joint venture with Reliance Industries.

This includes a retail service station network and aviation fuels business across India.

It builds on Reliance's retail network with plans to grow from around 1,400 sites to 5,500 over the next 5 years in one of the world's fastest-growing fuels markets.

The energy transition also remains front of mind.

We announced a further expansion in China through a joint venture with DiDi, the world's leading mobile transportation platform, to develop electric vehicle charging infrastructure across the country.

By combining our global retail capability and DiDi charging expertise with DiDi's large and growing customer base, we have an exciting opportunity to further develop our advanced mobility agenda in the world's largest electric vehicle market.

And we announced last week the development of BP Infinia, an enhanced recycling technology capable of processing particularly hard-to-recycle plastic waste into recycled feedstock, supporting a stronger circular economy in the polyester industry.

Finally, in an industry first, we plan to deploy continuous methane measurement across our new BP-operated major oil and gas processing projects.

This move is part of our wider strategy to tackle methane emissions in our operations.

It is ultimately aimed at delivering and improving on BP's performance in reducing our methane intensity.

Looking now at the broader macro environment.

Brent crude prices averaged $62 per barrel in the third quarter compared to $69 per barrel in the second quarter.

Following the attack on the facilities in Saudi Arabia, prices temporarily spiked, although this was short-lived due to a faster-than-expected recovery in Saudi production.

Prices were also tempered by rising trade tensions and increasing concerns over demand growth.

Forward pricing is expected to continue to be influenced by a number of competing supply and demand factors, including future OPEC+ production strategy impacts many further unplanned outages, U.S. tight oil production performance and the extent of the global economic slowdown.

Turning to gas prices.

The Henry Hub gas price fell to $2.20 per million British thermal units in the third quarter.

This was driven by rapid growth in natural gas production and by storage levels returning to their historical range.

Asian and European spot prices were weighed down by continuing rapid growth in LNG exports, averaging $4.70 and $3.30 per million British thermal units, respectively.

Looking ahead, we expect natural gas markets to remain oversupplied through 2021.

The combination of slower economic growth, slower Asian LNG demand growth and new LNG projects starting up is expected to result in some LNG export capacity being curtailed or underutilized.

BP's global refining marker margin dropped to $14.70 per barrel in the third quarter, slightly lower than the second quarter.

This was driven by weak demand growth, which led to a buildup of product inventories despite the high levels of refinery maintenance around the world.

The Brent-WTI differential narrowed in the third quarter as new Permian takeaway capacity eased logistics constraints.

And the WTI-WCS differential remained narrow due to tight heavy crude markets and ongoing production cuts in Alberta.

Looking to 2020, margins in light heavy crude differentials are expected to be supported by increased demand for marine diesel and very low sulfur fuel oil needed to meet the IMO's new MARPOL bunker fuel specifications.

Brent-WTI is expected to narrow further as new pipeline capacity comes on stream out of the Permian.

Now moving to our results in more detail.

BP's third quarter underlying replacement cost profit was $2.3 billion compared to $3.8 billion a year ago and $2.8 billion in the second quarter of this year.

The underlying effective tax rate for the quarter was lower than previously indicated mainly due to higher-than-expected estimated Rosneft earnings and the lower-than-expected impact from the Upstream profit mix.

Compared to a year ago, the result reflects lower Upstream liquids and gas realizations as well as lower production due to adverse weather impacts and maintenance activities, lower U.S. heavy crude differentials and the higher tax rate.

Compared to the second quarter, the result reflects lower Upstream liquids and gas realizations, adverse weather impacts on production and a higher tax rate.

This was partly offset by lower refining turnarounds and a higher Rosneft contribution.

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

Turning to cash flow and sources and uses of cash.

Excluding oil spill-related outgoings, underlying operating cash flow was $20.6 billion for the first 9 months, of which $6.5 billion was generated in the third quarter.

This includes a working capital release of $600 million for the first 9 months, of which $100 million was in the third quarter.

Organic capital expenditure was $3.9 billion in the third quarter and $11.3 billion for the first 9 months of 2019.

Turning to inorganic cash flows.

In the first 9 months, divestments and other proceeds totaled $1.4 billion.

We made post-tax Gulf of Mexico payments of $2.5 billion.

And inorganic capital expenditure was $4 billion, including final payments to BHP of $3.5 billion.

Through our share buyback program, we bought back 52 million ordinary shares in the first 9 months of 2019 at a cost of $340 million.

So far in the fourth quarter, we have purchased a further 80 million shares at a cost of $500 million.

At the end of the third quarter, net debt stabilized and was flat versus 2Q at $46.5 billion.

Following the non-cash impairment charge taken in the quarter and related impact on equity, gearing was slightly higher than the second quarter at 31.7%.

Turning now to some operational highlights.

In the Upstream, we have brought 23 of the 35 planned major projects online since 2016.

We continue to make good progress towards the delivery of 900,000 barrels of oil equivalent per day of new major projects production by the end of 2021.

Raven, the third stage of the West Nile Delta development in Egypt, is expected to start up around the end of the year.

So far this year, we've taken final investment decisions on 5 projects, most of which are in high-margin advantaged oil regions.

In exploration, we have had access awarded in 9 countries.

And in the third quarter, we won 2 licenses in the prolific Santos and Campos Basin offshore Brazil, with other access in Australia, the Gulf of Mexico and Oman.

We're also making good progress on activities to reduce our emissions.

Our $100 million Carbon Fund has so far approved 12 projects, all focused on delivering new greenhouse gas emission reductions in BP's existing oil and gas operations.

And we've rolled out methane measurement technology in 5 countries, with more planned by the end of the year.

In the U.S., we are using drones and handheld cameras to identify and reduce methane emissions in the U.S. Lower 48, including in the Permian where we are designing new facilities and retrofitting existing facilities to effectively reduce routine flaring over time.

In the Downstream, we've also made good strategic progress.

In addition to the new joint venture with Reliance in India, we've continued to expand our convenience retail network.

In Germany, we opened our 500th REWE To Go site, delivering a strong customer value proposition and differentiated returns.

In manufacturing, Solomon refining availability for the quarter stood at 96%, with record quarterly throughput at our Whiting and Cherry Point refineries in the United States.

In petrochemicals, we signed a memorandum of understanding with Zhejiang Petroleum and Chemical Corporation.

Together, we will explore the creation of a new joint venture for a 1 million tonne per annum acetic acid plant in China, utilizing BP's proprietary technology.

In the U.K., BP Chargemaster launched 150 kilowatt ultrafast EV chargers at our BP retail sites.

This marks the start of our rollout of more than 400 ultrafast chargers across the country in the next 2 years.

This, together with the joint venture agreement in China with DiDi, further underpins our ambition to be market leader in these countries with the fastest, most convenient electric vehicle networks.

And finally, Lightsource BP has added around 600 megawatts to its project portfolio through a number of deals including in the United States and Spain.

These deals further progress Lightsource BP towards its stated ambition to develop 10 gigawatts of solar capacity by 2023.

Looking to the guidance for the fourth quarter of 2019.

In the Downstream, we expect a similar level of turnaround activity and seasonally lower industry refining margins compared to the third quarter.

In the Upstream, we expect production to be higher than the third quarter following the completion of seasonal maintenance and turnaround activities.

For the full year, we now expect organic capital expenditure to be below $16 billion, reflecting a continued focus on capital discipline and efficiency of spend.

As indicated, we expect gearing to remain above the top end of our target 20% to 30% range through the year-end, reflecting the impact of the noncash impairment charges taken this quarter.

The remainder of our full year guidance is unchanged.

The DD&A charge is expected to be around $18 billion.

Gulf of Mexico oil spill payments are expected to be around $2 billion, net of tax adjustments expected in the fourth quarter.

We expect to continue our share buyback program and to fully offset the impact of scrip dilution since the third quarter of 2017 by the end of this year.

Since recommencing the program in the fourth quarter of 2017, the total number of shares bought back stands at 230 million at a cost of $1.5 billion.

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

And in the current environment, we continue to expect the underlying effective tax rate to be around 40%.

We approach the end of 2019 with a clear focus on executing the strategy we laid out almost 3 years ago.

We are making tangible progress across the business segments towards achieving our strategic milestones, all of which is underpinned by resilient financial frame.

We have made significant progress on the program to deliver greater than $10 billion of divestment proceeds through 2019 and 2020.

As indicated, we now expect to have announced around $10 billion of transactions by the end of 2019.

Assuming recent average oil prices and in line with expected growth in free cash flow and receipt of divestment proceeds, we continue to expect net debt levels to reduce and gearing to move towards the middle of our targeted range of 20% to 30% through 2020.

With the continued momentum across the business and confidence in our medium-term financial frame, we have announced a suspension of the scrip dividend program.

This is effective for the third quarter dividend announced today payable in the fourth quarter.

We do not anticipate offering a scrip election for the foreseeable future.

However, we will retain the option to do so, subject to continuing shareholder authority.

In addition and acknowledging that many of our shareholders value having the option to receive shares in place of a cash dividend, we are reinstating a dividend reinvestment plan.

Subject to election, this will allow some shareholders to reinvest their cash dividend to buy shares in the market.

And as net debt and gearing reduces, we remain committed to growing distributions for shareholders in line with sustainable free cash flow growth over the long term.

Before I close, I'd like to reinforce a few points about BP's approach to the energy transition.

In early 2017, we laid out our current strategy, which is underpinned by safe and reliable operations.

Since then, we have established a clear track record of operational and financial delivery, which has created a strong foundation for us to advance our low carbon agenda.

We are doing this while also responding to a rapidly changing energy landscape with growing expectations for us to adapt at pace to changing demands from stakeholders.

At our AGM in May, we supported the resolution brought by a group of shareholders seeking to broaden our reporting on how our strategy is consistent with the goals of the Paris Agreement.

A lot of work has already been done, and we expect to report on this ahead of next year's AGM.

In summary, however, we continue to be committed to managing our portfolio for value and investing with discipline in flexible and resilient options, which together support our broader strategy in remaining consistent with the goals of the Paris Agreement.

We are doing a lot, but there is more to do.

We know the world is not on a sustainable path and requires a faster transition to a low carbon energy system.

And we have an important role to play.

As we advance the energy transition and with the announcement of Bob's retirement and Bernard's succession as CEO, we will now move our proposed event in November to early next year.

Thanks for listening.

And let me now turn over to questions.

(Operator Instructions)

Okay.

Thanks again for listening.

We'll turn to questions and answers.

(Operator Instructions) We'll take the first question then from Os Clint at Bernstein.

Yes, 2 questions.

Firstly, Brian, just on realizations, you mentioned that in your commentary, particularly interest in U.S. realizations which seemed to be particularly weak here in the third quarter especially versus second quarter and last year.

And obviously, you've got a lot of the Lower 48 liquids coming in, but you did have that in the second quarter, so just looks like something much weaker in 3Q.

That's the first question.

And then secondly, just around the dividend, obviously, you got it growing again.

Last year, I think in the first half of the year around the quarters, you signaled potentially something could happen in the second half of 2019.

You haven't done that today.

So with the progress, could you just talk about this?

Is the Board discussing kind of boosting that dividend for the fourth quarter of 2019, please?

Thanks, Os.

And I think on the first one, realizations, it's really just about the bases of the various pricing points in the United States.

Average realizations were down, I think, about $6 quarter-on-quarter or thereabout.

The actual markets were down by a similar sort of amount.

I think actually, their difference is around about $52.

And it's really just about basis risk and what's happened, particularly WTI versus Brent.

And particularly the mix, if you look at the mix of barrels, which is probably the biggest driver, with the Gulf of Mexico barrels being out off the back of the hurricane and the maintenance and turnarounds, you just got those less high-margin barrels coming through in the average realizations.

That was probably the biggest driver basis, Gulf of Mexico.

On dividend, we did announce -- I think it's an important signal in terms of confidence around future cash flows.

We did announce that we're canceling the scrip from this quarter onwards.

And we don't envisage that we'll be issuing a scrip going forward, notwithstanding we'll keep the flexibility that we were given at the AGM, which we'll use in 2021.

So it may be something we'd come back to, but right now, the assumption is we won't.

We will have offset -- by the end of this quarter, we will have bought back all of the shares that have been issued since the scrip was introduced in the third quarter '17 when we signaled that.

And indeed, we've bought back already to date about over $800 million of share buybacks, about $350 million in the first 3 quarters.

And we've done $500 million in October, which you may have noticed.

So we are deploying cash to buy back the dividend.

We have the disposal proceeds.

As they come in next year, that will start to see the balance sheet deleverage.

So I think the strong message this quarter was net debt stabilized.

Gearing went up, we're now at 31.7%, and we've said it's one of our key measures now to get gearing back down towards the middle end of the range by the back end of next year.

So I think now would've been premature to move the divi.

And I think actually now with the Board, as we change out and we go through the Chief Executive succession, I think it probably signals the dividend will come back.

We'll certainly discuss it at 4Q, but it's more likely it will be beyond that.

But I think the cancellation of the scrip this quarter was an important signal.

As the cash flows come through from the disposal proceeds next year, the balance sheet deleverages.

As that gearing comes back down below 30%, I think that will then create a signal that would allow us to go and look at further distributions, either through dividend or through buybacks.

But I think we need to sort of look at where the company is going by the middle of next year strategy-wise, and that will help shape the picture going forward.

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

Brian, 2 questions from me as well.

Firstly, presumably it's fair to say that the difference between the dividend and the buyback is the difference between what you and the Board regard as sustainable and supernormal free cash flow.

And then if we have a company like yourselves with a somewhat weaker balance sheet, any supernormal free cash flow, if you have any, will be used rather to delever and return via buybacks.

You talked about buybacks in Oswald's question.

But my question I guess is, as a base case for 2020, can we expect from BP a discretionary buyback program?

And then secondly, the comment you made on the update previously planned for November now postponed to early 2020, is that going to be an updated strategy update where you will provide guidance to, say, 2025 around cash flow, dividend and CapEx, et cetera?

So maybe I'll take -- well, actually, on the buyback question.

So I think first of all, it's important to recognize, as you look at BP within the sector, our gearing is where it is.

There are a number of reasons for that, but probably the biggest and primary reason is the fact that we paid out $18 billion over the last 4 years in Deepwater Horizon payments and settlements associated with that incident.

And so therefore, we shouldn't forget that's the reason why we are where we are.

If that $18 billion our gearing -- without the $18 billion, our gearing would be down 22%.

So we have to recognize that, that wasn't going to go in the way of strategy.

And that's why off the back of the BHP transaction, we were happy for gearing to go back up higher.

In terms of discretionary buybacks, it's within the armory.

But I think you have to start to see the proceeds come through from the $10 billion program, which should be pretty much -- that program, we said over $10 billion, we should have the $10 billion done by the end of this year in terms of announced.

And then, of course, the last, it probably closes sometime around the middle of next year.

And there's phased payments associated with that.

We have deposits that have already come in, in the third and fourth quarter.

All of that will create the backdrop for flexibility in terms of distributions.

It would be premature to say that -- to say anything specific about that now.

But buybacks are definitely within the armory and available to the Board.

And if you think about the amount of scrip issued pre the third quarter 2017, there is no question that reducing the number of shares in issue helps self-reinforce the affordability of the dividend going forward, which clearly is affordable within the current frame.

But as we look to grow the company going forward and what the future options may look like as we look beyond the next decade, then I think that opens up a series of possibilities for us.

And that comes on to your second question, which was November was set up as an update on where we've been vis-à-vis 2021 and the targets that we'd laid out.

Fleshing out what we were doing around some of the new energy frontiers and in particular talking about what our low carbon ambition would be going forward.

And we just felt it was right now to leave that to be reset in the early part of next year as Bob hands over to Bernard and allow Bernard to really lean into the discussion around what we will be doing in the lower carbon space and the energy transition.

And indeed what the ambition of the company is going forward in that space along with what we're looking to do in the very, very long term in terms of 2025.

So I think you should assume that early next year, what we were originally planning for November will be an update on 2021 and some of the fleshing out of what we believe our ambition is in the low carbon and energy transition space.

And then I think a longer-term 2025 conversation is almost certainly in the second half of next year as Bernard takes over the reins and starts to shape where he would like the company to go collectively with the team.

So I think you should think about the first part of next year really around the ambition and what's the company's ambition in the energy transition and then second half of next year 2025 strategy.

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

I have 2 questions as well.

Brian, if I just come back to that idea of what happens with the share buyback when the dividend increase, I kind of suspect you're not expecting any major changes from Bernard taking over to what Bob was planning.

It's just that, as I said, that you're delaying things a little bit because of that, the change in CEO.

And then secondly, can I just come back to the write-downs from the quarter associated with the divestments?

Is there anything else that we should be thinking about in terms of the balance sheet that may trigger further write-downs in terms of whether it will be lower oil price that you're using or not?

Thanks, Lydia, and thanks for the opportunity to just clarify.

No, don't signal anything in terms of Bob to Bernard, that there is any change in dividend policy or our view going forward.

We may well come back to dividend as part of 4Q, but I think we'd like to see net debt and gearing turning back towards below 30%.

And on that basis, we may well look at a 4Q, and it will be based on the outlook of where we are vis-à-vis proceeds, what the trajectory looks like in terms of future cash flows.

It's not a function of Bernard having a different philosophy to Bob around dividend.

That still stays the same in terms of progressive dividend and where the company sits.

On write-downs, what you saw come through this quarter is really a function of the fact that dry gas -- the dry gas assets we're selling off the back of the BHP transaction, the assets -- the legacy assets inside BP, clearly where Henry Hub is, and we talked about it on the call, I think we anticipate gas prices are going to remain pretty suppressed certainly up to 2021.

If you look at the fact that the U.K. I think is 105% full on LNG right now, Europe is full on LNG imports.

We don't anticipate that all of the gas that was planned and slated to be exported from the U.S. will be able to hit a demand market anytime soon.

And so therefore, actually, strategically, we were looking to get out of these assets.

We chose to proceed.

We're still getting good multiples of what the forward prices look like in terms of the prices we're achieving for the assets, but they're clearly below what was being held at book value, and that has led to these impairments.

To the degree that we have more packages, and we have at least 2 of the packages in the fourth quarter, and the assumption we were to proceed with sales of those packages, they will be -- potentially have the similar issues to what we've talked about this quarter.

But I'm not signaling that we're expecting any other big major impairments in 4Q, but there could be more to follow depending on what prices we achieve for those assets.

We'll take the next question from Dan Boyd with BMO in the U.S.

I wanted to just get an update on your Lower 48 strategy with BPX.

So can you give me an update on your thoughts on capital allocation there?

I was specifically interested in just how you think about allocating capital between the 3 basins given that, at least according to the public data that we can see, your Eagle Ford results appear to be top quartile in the industry, but you reduced activity there.

And then are there any commitments that are preventing you from reducing Haynesville activity just given what we're -- basically reducing Haynesville further given what we're seeing with gas prices?

And then an update on when you might increase your Permian activity.

I think previously, you talked about as there's more takeaway capacity.

Right.

So right now -- I think actually, you've almost answered the question for me, which is the focus is absolutely on Eagle Ford.

You were backing our production straight into WTI pricing.

It is by far the most attractive of everything we can see in that Lower 48 slate right now.

We had the Board meet with the team in Denver in the third quarter in September.

We were able to go back and review where we are, I think the performance of the rigs that we're already drilling.

We've already drilled 73 new wells.

In the third quarter, we drilled 28 in Permian, 32 in Eagle Ford and 13 in Haynesville, and that kind of gives you a sort of a sense of priority right now, which will be Eagle Ford first.

We will ramp up in Permian probably later into next year, certainly into the middle of next year, as takeaway capacity comes on stream.

We are seeing things in terms of the Austin Chalk which we hadn't originally built into our case in terms of the acquisition of BHP, which looks really interesting.

We're getting much lower water cuts than we anticipated in some of the wells, higher oil-rich numbers coming through.

And probably most importantly, the synergies that we've put in place, the $350 million by 2021, we'd slated $90 million of synergies anticipated this year.

That's already at $240 million this year.

So I would say, in terms of BPX, capital-wise, we're still allocating just over $2 billion of capital into those assets.

I think they give us huge flexibility in terms of the ability to ramp up.

And it's actually in the priorities, you said it's Eagle Ford, then it's Permian.

And Haynesville, we've ramped down significantly, which is natural given where you see the gas prices.

And in some respects, we're doing the minimum of what we need to do inside that basin.

But I think pretty much it is Eagle Ford, Permian, Haynesville.

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

Michele?

Congratulations on getting the disposals done despite a difficult environment.

I was wondering, on the $10 billion of disposals, how much cash flow is associated with that which you will lose over the next 12 months?

And then if I could ask a second question, given the write-downs, given the ramp-up in the Lower 48, should we expect the depreciation of $18 billion to start coming down in the coming years?

Thanks, Michele.

On the first one, actually, a lot of the assets we're selling are cash negative.

The one exception would be Alaska, which was surplus cash and generated cash.

But we've built that into our targets.

So in terms of the 2021 targets of $14 billion to $15 billion of EBITDA, free cash proxy out of Upstream, that number is unchanged.

And if you recall, we've moved that number up by $1 billion when we did the BHP acquisition.

So nothing in terms of future targets.

And some of these assets we're selling are actually cash negative if you look at some of the dry gas assets in the United States.

And then the second part, in terms of DD&A, yes, you're right, we would have -- we've taken the impairments.

That will have a small impact, but nothing at this point where we'd indicate having a major change going forward given the amount of capital we still got going into the system of around $16 billion and some of the acquisitions that we've had.

I think right now, it's a bit too early to guide into what would happen with DD&A going forward.

We'll take the next question from Chris Kuplent at Bank of America.

Chris?

Just 2 questions on your -- I'm going to call it trading statement or the press release the other week, following on from what Michele just asked.

I appreciate most of these are free cash negative, but maybe you can give us a little more detail because the $10 billion number, correct me if my math is wrong, means that you have sight on $3 billion roughly of additional or new disposals that we haven't seen yet.

So I wonder whether you can give us any more information not just about the free cash negative contribution but CapEx or production or any other items that you can help us with in terms of modeling the impact from these additional disposals.

And secondly, just wonder whether you can clarify the expectation of a 50% tax rate that you highlighted in that trading statement and what occurred since.

Yes.

So in terms of -- it wasn't actually -- Chris, it wasn't a trading update.

It was -- we don't do trading updates.

But it was simply a guidance of -- given that we had -- we knew the impairments were coming down, down the pipe, we thought we'd do an update, sort of a market wrap on a variety of aspects and different things.

But in terms of the assets that are left now for 3Q, we've already signaled that we anticipate we will announce the $10 billion.

The last tranche for 4Q, which we're right in the middle of and close to announcing, is a mix of Downstream, Midstream and Upstream.

So it's a very different mix from what you've seen already year-to-date.

And again, any assumptions on the cash flow associated with those is already built into the forward profile in terms of targets.

So there isn't anything specific I could give you in terms of cash mix for the fourth quarter, but they are built into the long-term targets.

And then on the tax rate, the big change -- actually, when the note went out 2 or 3 weeks ago, we were looking at a tax rate at that point from the early numbers of about 52%.

The biggest change was Rosneft earnings have come in significantly higher.

Those numbers come in post-tax.

That was 5% delta versus the 50%.

So just with these sort of earnings of what we were expecting and what I think the market was expecting from Rosneft, that would have moved the tax rate to 45%.

And then the mix was actually stronger Downstream, which runs at a typical lower tax rate to Upstream.

And then the balance of mix of the profits out of Upstream was stronger towards some of the high-margin barrels that have been anticipated when we actually moved the guidance to say that, actually, we're anticipating something around 50%.

But there were 2 -- effectively 2 big major moves: one was Rosneft, which was the biggest; and then Downstream earnings coming through stronger than we'd anticipated.

Okay.

That's clear.

And sorry for going on about it, but can you confirm the $3 billion roughly, my math, if I add up Alaska and what you've done in the first half?

We've done $7.3 billion or $7.2 billion, I think, up to the end of 3Q, which means $2.8 billion this quarter.

And I have got line of sight of more than $2.8 billion.

And the question you didn't ask is -- but I may as well answer is, are we done with $10 billion?

The answer is no.

There will be more disposals next year over and above the $10 billion.

The $10 billion was over $10 billion, as what we laid out, so there will be a series of portfolio divestments beyond that.

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

Two questions.

Firstly, on the third quarter Downstream result, particularly the fuels value result seems very, very strong.

Can you talk around a little bit about trading contribution, other drivers and also your expectations because, clearly, on the macro side, you are quite positive on higher margins due to IMO?

The second question, in your opening remarks, Brian, you referred to BP potentially entering a transformational period with Bernard as the new CEO.

What should we read in that transformation, please?

I think I'll pick up the latter first if that's okay, Irene.

I think it's just the pace of change that we believe we will require going forward.

And I picked this up this morning that, actually, it's not a reflection on Bernard versus Bob in terms of style or approach.

It's the fact that we have learnt a huge amount.

As we were able to deal with the financial -- the $67 billion financial fallout of Deepwater Horizon and as we came into 2015 after the 10-point plan, the low carbon agenda emerged out of the Paris Accord in 2015, which is a major step forward.

If you think that BP back in 1997 first laid out its ambition in this space, '15 was a really defining moment for us.

And that's when Bob and a number of his peers came together as OGCI, which is an organization that Bob chairs and I think today has about 1/3 of the world's oil production within its membership, came about and started to talk about the ambition for the sector.

But of course, society and investors and shareholders are moving at a rapid rate of knots.

And therefore, in some respects, Bernard coming in, he arrives at a time when we're seeing huge change.

We're seeing huge change in terms of society and what society expects.

And if you think about what Bernard has done in the Upstream in the last 2 or 3 years around particularly leading on digitization and what he's done around the low carbon fund that we've put in place, I think he and his team, and we have learned a huge amount about that, so I think it's an opportunity.

Whenever there's a change at the top, it's an opportunity to slightly move the ship in a slightly different direction, in this case, plotting perhaps a maybe more pacey course.

But I don't want to sort of get out ahead of what Bernard will lay out in the first quarter of next year, but I think you will definitely see -- and if you've seen Bernard in the last year, you will see him leaning into that debate in the same way that Bob actually got the company back into the alternative energy space back in 2015 post the Paris Accord.

So I wouldn't read much more than that into it, but I think there's more to follow.

As I say, I'll let Bernard sort of lay out his thoughts on that in the first quarter of next year, but I think it's a huge opportunity for the company and just reflects on the pace of change that we're seeing out in society.

In terms of third quarter results, Downstream, it was a strong oil trading result.

You know we don't give specific numbers around that, but you know we talk about our plan, average strong, very strong.

But it's a strong quarter for the oil trading.

That's helped Downstream.

But also in Downstream, we've seen refinery throughput improve hugely quarter-on-quarter post-maintenance periods.

And availability in Downstream is running at something like 96% I think was the figure that we had, which is extraordinary to have a system of that scale running at that sort of availability.

And even though margins were down quarter-on-quarter 2Q, 3Q, having the kit there running well means you can still capture what is undoubtedly a lower margin but not that much lower, and that's why you're seeing the stronger earnings come through.

You're also seeing slight improvements in loops and in fuels.

And of course, we've got -- in terms of Downstream, we have major progress on new markets that you'll have seen come through this year, which I think over 1,250 new market sites we now have in place across Mexico, China and further afield.

And we have the Reliance deal that we announced with India, which is a really big deal in terms of one of the fastest-growing markets in the world and with a partner that we know well.

And we trust and have worked with Mukesh and Reliance over a number of years.

And that will create a truly deeply strategic alliance.

So I think a lot of good things happening in Downstream.

We saw that come through in this quarter, culminating what was a strong oil trading result which helped the fuels value chain and strong availability and performance of the kit.

We'll take the next question from Martijn Rats at Morgan Stanley.

I had 2, if I may.

First of all, I wanted to ask you about the Upstream results.

I guess that in the Gulf of Mexico, partly to hurricanes and turnarounds, the result was negatively impacted.

But also the non-U.

S. result doesn't look so great, and I was wondering if there is something to be said about the Upstream result outside of the United States.

And then secondly, it's something from the sort of very short run to the very long run.

There was a general sort of idea that companies like BP spend only a very small portion of their CapEx budget on new energies.

But it seems to me that a lot either goes through project financing or joint ventures or sort of other ways that effectively means that BP is affecting a lot of investments without it necessarily being captured in your reported CapEx numbers.

And I tried to do some numbers on this, but it's very, very difficult.

I was hoping you could give us perhaps some quantification of the amount of CapEx that you're actually affecting through the Chargemaster, Lightsource, all the other JVs that you have and project financing because my suspicion is that you end up with a much, much bigger number.

Actually, I'll come back to that second point, Martijn.

That's a great point.

And I can elaborate a little bit more on that.

You'll see Bernard may talk a bit more about that in the first quarter of next year.

In terms of Upstream, it's pretty straightforward.

It's really about the drop in oil price and realizations that we saw.

If I just take outside the United States, we had lower oil and gas realizations, slightly higher cash costs off the back of some turnarounds.

But also we had a lower oil gas ratio, and that's really -- it's the mix of oil versus gas in the non-U.

S., which is really what's sort of driving that results and that delta that you can see from second quarter to third quarter especially in terms of underlying dollar per barrel.

On the new energy space frontier, you're absolutely right, if you look at what Dev has been doing with particularly alternative energy and, yes, the best example would be Lightsource BP, although equally BP Bunge will be another example of that.

But Lightsource BP is something like a 200 to 300 -- about $250 million investment or thereabout, which has generated something like leveraged $7 billion worth of investment, which is building towards a potential 10 gigawatt installed capacity in terms of solar.

So I think the financing models are very different.

We're going to talk more about that in the first quarter of next year to show you what those models look like.

But of course, some of those things will also then come back into the mothership at some point as they start to deliver earnings and returns because, of course, the investment model is a very different investment model in those new energy frontiers.

And you can see that through the venture fund.

If you recall, actually, I remember when we did 1Q results, we were all on the West Coast in Los Angeles meeting with all of our venture partners on some of the new energy frontiers in terms of some of the ventures we look like, it's Solidia and Silicon -- and other new processes that we are focused on.

They do have a very different investment profile.

And we will show you as part of next year, as we're thinking about strategy out to 2025, there will be the traditional business which will be paying the dividend probably for the next 5 to 10 years and covering the growth and allowing us to find cash to deploy into these new energy frontiers, which is called oil and gas.

And that will be a more typical financing model that you see today, which is about how the capital and operating cash can cover the capital and the dividend.

But then we'll also talk about actually what our ambition could look like in some of those new energy frontiers in a place where we really need to accelerate pace and grow out some of that portfolio.

And that portfolio may not be as straightforward as simply a renewable.

It may be a renewable integrated with a more carbon-like solution, whether it be a mixture of wind with solar, with natural gas-powered turbines.

So there's a number of potential options for us going forward.

And one of the important parts of that space as we think about it and what the financing looks like will be trading because trading will be at the essential hub of a lot of what we do around energy management.

And the sort of financing that's required to bring on some of these projects, we'll be using trade finance.

And then we'll also be able to trade in terms of the inputs going in to facilities and the outputs coming out in terms of power.

So it is a huge opportunity for us.

We're going to give you a lot more detail on that, Martijn, next year.

But we are -- as we think about our 2025 thinking, we're thinking about financial frame for the traditional business which, as I said, will pay the dividend over the next decade, and what the financing frame may look like for these new energy frontiers, some of which will come back into the mainstream of our business as we go forward.

But that's a little bit -- that's more of a teaser, I think, in terms of what you expect in the second half of next year.

We'll take the next question from Lucas Herrmann in Exane.

Brian, a couple of quick ones, if I might.

Firstly, just going back to the Gulf of Mexico, Brian, can you give any indication as to the level of barrel you'd expect to come back in Q4?

It looks as though about 60,000 barrels were off in Q3.

And secondly, slightly more long term.

Egypt, given where LNG prices are, given the build in gas supply in Egypt, are you starting to come under or seeing any pressure from the authority to contain the build in supply, whether it's oil, whether it's, I think more appropriately, West Nile Delta in your case?

What are the messages from the authorities at this time?

Great.

Thanks, Lucas.

Nice to see you at Exane.

It's a new name to see.

Probably took me a bit of time to get used to that as I looked at that.

It's about 100,000 barrels a day were offline in the third quarter, mix of hurricane, turnarounds and the few unplanned outages.

But something around 100,000 barrels a day net was offline in the third quarter as a result of that.

Does most of that come back, Brian, if you recall?

I can't comment.

We've said our production will be up in the fourth quarter versus the third quarter.

Some of that will come back.

But obviously, the hurricanes won't be affected.

The turnarounds were through, so the majority of that should come back in this quarter.

And then in terms of Egypt, Craig, is there anything you want to add on Egypt?

Yes.

Well, I think -- I mean we've been focused there, as you know, Lucas, in the Mediterranean in terms of starting up the gas projects there.

We've had 2 startups so far over the past year or so with Phase 1 and Phase 2, Taurus, Libra, and then Giza/Fayoum.

The next big project to come is Raven.

Brian already mentioned we're expecting that around the end of the year.

That's a significant project.

It's about 160,000 barrel a day project on a gross basis that we're expecting.

That will ramp up partly at the end of this year but I think significantly through next year and is a key contributor, I think, over the next 2 years to meeting our production target.

It's an 8-well program.

It's about 99.6% complete.

And as I say, it's around the end of the year.

In terms of your question around coming under increasing pressure, not had any sense of that coming out of Egypt.

It's a country we've been in for many decades.

It's a relationship we hold very close and one that's very important to the company, and it will continue to be so.

But no, nothing explicitly on that.

And I think maybe just to add as well, if you think about -- historically, we've talked about the big profit centers in the Upstream.

There's no question now, Egypt, with the amount of activity going on in those, it's now certainly one of the significant profit centers we have around the globe and certainly sits there alongside Azerbaijan, North Sea, Gulf of Mexico and Angola.

We'll take the next question from Jon Rigby at UBS.

Brian, a question on the Downstream.

It looks like the third quarter sort of shows what your refining system can do, and it's running well.

And I was struck by your guidance of 4Q saying refining margins are down, although I know to-date they are.

And if that's an IMO effect, which I think a lot of people think may continue into next year, I was just wondering where you stood in terms of some scheduled turnaround activity you're prepped for next year.

Can you keep that network going hard over a number of quarters, over the next few quarters to take advantage of what might actually be better conditions?

And then the second question, just excluding this quarter with the sort of 50% to 40% tax rate, if you have been sort of going along at high 30s, 40% tax rate, is that still a reasonable view about what the underlying portfolio will look like into 2020 and '21 as you can see it?

Yes.

Maybe on the second part first, Jon, you'll appreciate this more than most with your background way back, which is tax is hellishly difficult in a company as large as this.

And as you've seen even from 2 weeks ago, a 10% change is quite significant.

So I think for the year, a 40% guidance is still good, but there's a lot that can move around, around deferred taxes, around exchange rates, around what comes through in terms of some of the subsidiary companies and their posttax earnings that get reported.

So there's a lot of moving parts.

But needless to say, given we sent you a note a couple of weeks ago saying we expected 50% and it's now at 40%, we've actually gone back and looked at everything in terms of taxes.

But 40% still looks like a good number for the year.

It may be a toppy number based on what we can see right now, so it could maybe close to 39%, but I don't think we'll see the 50% again.

And actually, interestingly, had we had the 50% tax in 3Q, that would've taken the year-to-date to 40%.

So it's sort of had a symmetry to it and logic to why that was where we were sort of getting at, at the time.

But I think 40% for the year still looks pretty good, but there's a lot of moving parts.

In terms of refining, you're right.

And I was on the trading floor last week with the traders trying to sort of do around the houses on natural gas, on oil, trying to understand a bit more about what's going on in the markets right now.

And I think finally, MARPOL is starting to kick in, and you're absolutely right that that's what we're seeing in the refining margin right now in terms of underpinning.

It's certainly not coming from gasoline.

But I think it's certainly what we can see is MARPOL keeping refining margins where they are.

We just assumed they will drop off seasonally because the winter is here.

Yes.

We're through the driving season, demand will tend to typically drop off in the fourth quarter.

In saying that, runs are up, and refining margins are up.

So we still anticipate we'll see that winter correction come down as the quarter progresses, which is what we've given in terms of guidance.

And then in terms of turnarounds, of course, we've been getting ready for MARPOL now for the best part of 2 years, both in terms of investments, infrastructure, blending, all the things that we'd be able to need to do to make sure that we were able to take advantage of that as that legislation comes in.

And needless to say, we've ensured that our turnarounds are set up in the pattern in which they have to happen because a lot of them are regulatory turnarounds that we have to do.

But nevertheless, we have done some pretty big turnarounds in our refinery system over the last couple of years.

So on that basis, you should assume that we'll be as configured as best as we can to take advantage of those margins going forward over the next couple of quarters.

We'll take the next question from Roger Read at Wells Fargo in the U.S.

Just a couple of things I'd like to follow up on.

One, the earlier comments related to the write-down of some of the assets about potentially seeing U.S. LNG export capacity underutilized.

And I'm just wondering, what if we see the flip side of that, which is the capacity gets utilized but at lower prices, how would you think of that potentially, the lower prices in the U.S., transitioning into the global market?

How do you think that could affect anything else in your international operations?

Or do you simply see it as prices, you're too low, we won't see you as LNG export capacity being competitive in terms of just being able to move it through the facilities and onto the water?

And then the second question I had was along the lines, as we think about the methodology and the future of dividend versus share repos -- I mean I understand the gearing down to the mid-20s.

But what else should we be thinking about if you examine or analyze and you're deciding to move forward with a dividend growth versus share repos and especially in terms of maintaining flexibility long term?

Yes.

Maybe just on the latter, I mean the philosophy of the Board remains the same, which is a progressive dividend that's sustainable into the future.

And I think as you look at the additional cash flows that come through in 2021, that gives us a huge amount of flexibility around both dividend and share repurchases.

And as I said before, there will be a bias in terms of the amount of shares we issued pre-third quarter '17 post scrip.

But I think they'll be a desire to move both on divi and on buybacks, but it's too premature for me to sort of talk about that in terms of we're getting into next year.

We've looked at the strategy of the company in the sort of second half of next year.

But I think on the current trajectory, I think the gearing and net debt coming down will be a stronger signal in terms of further distributions.

And that will be triggered by -- I think as I said before, the buybacks we're proceeding with ahead of divestment proceeds.

And you're seeing us do that this month in October and through this quarter.

We will defer about $1.5 billion to do.

So I think there'll be more to follow on that as we go into next year.

But I think the big signal will be balance sheet deleveraging will be the sort of facilitator for that.

In terms of U.S. export capacity, I mean you're absolutely right.

At $2.20, all of the United States gas under any normal rational market globally would be getting exported.

The difficulty is, from my conversations last week, gas is currently moving into Europe around about $4.50 right now, and so therefore, there is no way even at $2.20 Henry Hub in the United States, the economics is going to work for that pattern to happen.

Equally, you have this massive battleground called Europe.

And I think I said earlier that the U.K. is 105% full on LNG storage right now.

Europe is 100% full on LNG.

And we have the whole question mark of what will happen vis-à-vis Russia in terms of gas into Europe.

So I think Europe suddenly becomes a major sink for setting the global price as we see this wash of gas around.

And I think that inevitably means that you will see not all of the facilities being utilized.

I was only lamenting for talking last night about I remember back in the early parts of the sort of 2000 to 2004, when we were building Cove Point as an import terminal into the United States and all the import terminals that we created, we've now created a series of export terminals.

And while there's still no question that United States gas is the lowest cost of production in the world, it's going to be hard for it to find a market anytime soon in the next 2 years probably.

And you're probably looking at the back end of 2021 before you start to see this massive supply overhang clear out.

And remember, you have LNG projects coming onstream in Australia, Middle East and around the globe, which is simply going to exacerbate the situation.

So I think gas fields, certainly from the conversation I was having last week on the trading floor, gas fields are pretty bearish right now.

And therefore, you will see some gas exports out of United States, but I don't think they'll be anywhere near the capacity of what's being built.

We'll take the next question from Biraj Borkhataria at RBC.

Biraj?

I just have one clarification on the buyback.

I noticed there's some share kind of creep each year from -- I think it's from the employee incentive program.

Could you confirm whether you're looking to offset those shares as well with the buyback?

I'm just trying to get a sense of where the net share count goes the next couple of years.

And then the second question is on Gulf of Mexico payments.

I think year-to-date, you've done $2.5 billion, which is ahead of guidance.

I know previously, you've talked about the uncertainty on the tail, but it feels like, at least versus my estimate, every quarter is a little bit higher.

So could you just provide an update on where you are on that and the latest guidance for '19 and '20?

On shares to be repurchased, we've got about $1.5 billion left to do in the fourth quarter at the current prices, and so that will get done this quarter.

We haven't committed anything on the shares that are issued as part of the various employee schemes that we do over the years.

That's something we'll come back to, but we've not said anything specific around that.

And there's no intent to buy those back at the moment.

On the second part of your question, sorry, which was about -- could you just repeat the second part?

Sorry.

Just an update on the Gulf of Mexico payments.

Oh, yes, Gulf of Mexico.

No, it's -- yes, this quarter, it's pretty much de minimis in terms of there were no business economic loss claims this quarter.

The major part of the number that comes through this quarter is the unwinding of the discount that we have around the funding of the 18-year program that we had, so there's no material effects this quarter.

It's really around $2.5 billion for the year.

It will come back into guidance with a tax credit that we always get in the fourth quarter come through, so it will be tracking somewhere around about $2.2 billion by the time we get to the end of the year with the tax credit that we see in the fourth quarter.

But no, Gulf of Mexico is actually -- it's about -- I think it's come to about $18 billion by the end of this year over the last 4 years.

And next year, we move into just over $1 billion a year out to 2032.

So effectively, it is -- become a relatively modest dividend stream into the Gulf of Mexico states out to 2032, but that's pretty much under control now.

So actually, now everything is trending in the direction we said.

And while it looks like it's trending higher by the end of 3Q, you've got a tax credit to hit us in the fourth quarter, which should bring the number down.

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

Brian, 3 short ones, if I may.

Just picking up on your comments about gas overhangs in the next 2 to 3 years, does that make you think that the West African gas resources being discovered and defined is back-ended, next-decade kind of activity?

And then secondly, on Rosneft, is it your sense that the resource spacing there should be something to be cautious of for the fourth quarter?

And finally, just a quick one, Brazil, the transfer of rights around in early November, should we be seeing BP activity in that round at all?

Yes.

So in terms of gas overhang, I think it's so -- yes, there's a sort of a bear or bull story, which is 2021 is where the bulls are, that it cleans out by 2021.

The bears are sort of 2023.

Right now, we'd probably be in the 2021 space, so I think you will see the overhang of supply get cleaned out by the end of 2021.

And so therefore, I think these projects, I don't think that will impact on what's happening in terms of the West Africa projects.

I think they're going to proceed as per plan.

And I think you will start to get into more buoyant market as we get out to 2022 is where our current view is at the moment.

On Rosneft, we'll have to wait until Rosneft publish it, our estimates of their earnings.

There would have been some duty-like benefits come through this quarter.

I think that some other things have come through this quarter for them, so I wouldn't necessarily use that as guidance for 4Q.

And then in terms of Brazil and transfer of rights, we've already notified ANP of our decision not to participate on October 24.

And while we're interested in Brazil and we want some licenses in terms of explorations on both Santos and Campos, we won't be participating in the transfer of rights auction.

Okay.

We'll take the next question from Peter Low at Redburn.

Peter?

Just one last.

It was a question on your gas price exposures.

What proportion of your production is exposed to kind of the international hub prices, which might be susceptible to kind of the oversupplied market you talked about in your prepared remarks as opposed to, say, being on more resilient, local or oil-related pricing?

Obviously, any color on that would be appreciated.

Yes.

Henry Hub -- so actually, it's not so much just Henry Hub, it's the impact it's then having on Europe and the Far East in terms of pricing.

We're seeing some of the big producers of gas reduce their oil-related curves in terms of where they're now selling, in terms of pricing.

So it's not just Henry Hub.

It is actually a global phenomenon right now given the absolute amount of gas around.

We, of course, have a gas portfolio, which we've talked about during post the 10-point plan in the phase after 2015 through to '17, which is a bit more weighted towards gas and domestic gas.

And what that means today is roughly, roughly, if you look at our pricing, it's about 1/3 domestic in places like Oman and Egypt, it's 1/3 hub pricing and 1/3 international LNG, which is typically a percentage of Brent forward curve.

So it's about 1/3, 1/3, 1/3.

Okay.

We'll take the next question from Jason Gammel.

I had one question on the Lower 48 divestiture process.

Brian, I believe that at the time that the BHP transaction was announced, the intent was to largely divest all of the legacy Lower 48 assets with the exception of the Haynesville and the Eagle Ford, where you had some crossover with BHP.

So the question is, when the 4 packages that you've referenced are completed, would you expect that process of fully divesting the legacy 48 business will be done, or will you be retaining some assets there?

And then the second question I had was on the Reliance joint venture in India.

Can you talk about potentially how that benefits you just from a logistical standpoint and being able to potentially use their midstream and local downstream assets to improve returns and how you'll be sharing capital when it comes to the buildout of the network there?

Yes.

So in terms of Lower 48, assuming we get the final couple of packages away, and we may actually -- we may choose to or not do that with the final 2 packages, that will be pretty much most of the legacy position done.

But yes, the Lower 48, it's -- I've said this before, the United States is one of the most prolific basins in the world, and therefore, you should assume that with Dave and his team, now we've got these high-quality assets in the portfolio, we'll be looking to optimize that portfolio in terms of acquiring positions, divesting positions, high-grading the portfolio or within his own capital frame that he's got within Lower 48.

We've talked about checkerboarding before in terms of overlap of properties and assets with other companies and the ability to swap and move around the positions.

I think everybody, certainly in terms of what I call the big caps, mid-caps, will be looking to try and optimize their positions within their own counties of where they operate.

And we have got some opportunities to do that.

But you're right to assume that most of the legacy position, assuming we get the final couple of packages away, will be pretty much divested.

And the focus will be very much on the new in terms of the oil-rich options that we have going forward.

In terms of Reliance JV, it's one that we've been talking about over many years and culminated last quarter in the agreement to go forward.

It will have all sorts of opportunities.

It's not just fuels, it's aviation fuels as well.

It will have all sorts of opportunities to be able to use our own proprietary trading we have within BP, our own knowledge of midstream.

I think it will lead to all sorts of other options if we think about advanced mobility and some of the things that we may be able to trial.

There's no question India is one of those markets where they may skip some generations of mobility sources.

And so I think it will be a fantastic opportunity for us to -- why we called -- Reliance India JV was a deeply strategic move by the company with a partner that we know and trust well.

Mukesh Ambani is somebody we've worked with now over a number of years, even the days after Deepwater Horizon.

He's a good friend of the company.

His company is very important to us strategically.

And there'll be all sorts of opportunities that will come off the back of it.

But there's no question he will want to, as we will, use our expertise in the midstream and learn more about that market as well jointly with them.

But I think there'll be more to follow on that next year as we sort of get that deal closed.

And Tufan, I'm sure, will talk more about that at 4Q.

We'll take the next question from Colin Smith at Panmure Gordon.

Colin?

Just apropos of the earlier discussion around the journey with respect to carbon emissions.

I was just wondering, Brian, if you're sort of signaling here the potential for BP to accept responsibility for Scope 3 emissions because I know historically Bob has been relatively against that.

Thanks, Colin.

So I mean, first of all, it depends what you mean by Scope 3. There are 15 separate subcategories of Scope 3, so it's not simply a case of coming out and saying that you will or won't agree.

We already do a huge amount in the Scope 3 space in terms of making our products more efficient and therefore less carbon-intensive and less CO2 in the atmosphere.

So I think as we come out in the first quarter of next year, we'll talk more broadly about what it will take for the company to think about what its ambition will be in the very broad sense of greenhouse gas emissions and all those things which pollute the atmosphere, that are leading to global warming and the things that we can do.

I think Scope 3, in some respects, is a red herring in terms of kind of what we're trying to do and what we're looking to pursue.

We will look to reduce our footprint across the piece through a number of opportunities that we have.

And as I say, we'll talk more about that in the first quarter.

But Scope 3 is absolutely within the scope of what we're looking at.

But Scope 3 is not a simple declaration you can make given the 15 subcategories that sit within Scope 3, and I don't want to get engineering and analytical about this.

But ultimately, we have to make sure that right now, we are all clear that we're not on a sustainable path.

We need to go faster.

We need to control the things we can control as a company.

And we all need to make individual choices about what we do if we actually would come back to making sure that we ensure the planet is well below 2 degrees, which are the goals of Paris.

And that's something we've committed to as part of our AGM resolution and we'll be talking about in the first quarter and we'll be updating shareholders again at the May AGM.

We'll take the next question from Christyan Malek at JPMorgan.

Christyan?

Brian, sorry to submit a question so late.

But while your answers on the capital frame were clear, I want to follow up on the divestments in your shale.

Brian, so while suspending the scrip is welcomed and brings you in line with peers, in the Q2 call, I seem to remember that with the planned $10 billion of divestments and positive trend in cash breakeven is that, that would pave the way for additional cash return.

I know you've mentioned line of sight divestments a few times on the call, but I would like to understand better the timing of these sales and as far as cash in the bank.

Or put it another way, could you outline the risks that we should be aware of in delivery of the $10 billion and what key milestones we should be aware of?

The second question is around the production ramp-up in the U.S. shale and the key operational milestones achieved in -- you saw into Q3 and what surprised you and the team both positively and negatively some 15 months since the acquisition.

And just linked to that, assuming delivery, has the Board discussed the potential to scale up further in your shale for M&A, say, once the gearing is back in the range, or is cash return really the key priority by deleveraging?

Christyan, you're absolutely right to flag what we said at 2Q.

It's important.

Of course, gearing has moved up.

And I think, yes, that we are minded to get the gearing back below 30%.

It's gone the opposite direction off the back of the equity write-downs, which is natural.

Net debt actually stabilized.

But to sort of maybe get to the point in terms of proceeds, I would anticipate that the $10 billion program, we've got about $1.7 billion of proceeds in already at the end of 3Q.

I would anticipate we'll be somewhere closer to $4 billion by the end of the year of proceeds and with the balance to come next year, probably in the back half of next year given Alaska probably won't close until the middle point, maybe July of next year.

So that would take some time.

So I hope that gives you some indication in terms of how the cash flows will come through.

And I think I've already signaled earlier on the call, expect more disposals over and above the $10 billion, which will help accelerate the net debt coming down even further to get us back into a much more stronger position around that dividend question.

And then in terms of Lower 48, I mean I think across the piece, we had a great review with the Board back in September.

And I think every way we've looked at this acquisition, it looks better than we first thought.

The synergies, we're running at $240 million versus $90 million for this year.

The $350 million, I think we'll end up revising that number up.

Permian, we've already increased the rig counts up to 5 rigs.

In 2020, we'll come up to 5. Eagle Ford is running at 8 in 2020.

And Haynesville will probably come down a rig or so, as I said earlier, around the gas.

Performance of the wells is better than we anticipated.

The costs are running 10% lower than they were under the previous incumbent certainly in terms of Eagle Ford.

And look, I mean I think what you have to recognize is within the previous incumbent's portfolio, these assets weren't attracting the investment that we're now putting into them.

So naturally, as you start to ramp activity up in what is a basin with the techniques that we learned over the last 3 or 4 years, that David deployed, that he brought in from SandRidge, it's just a huge opportunity for us.

And you'll see more of this as we come to 4Q.

And I'm sure Bernard will lay out in terms of some of the things that we've through this year.

But I would say everything is very positive across the piece in those assets.

One of the things that we have seen though from a safety perspective is we've had slightly higher Tier 2 issues, which you will have seen come through the 3Q numbers.

As we onboard those assets, we'd expect to see those issues come down into next year.

So that's probably the only thing to highlight that as we lay out our process safety and the running of those assets, you will see those Tier 2s come down.

And so just around M&A in terms of just potential to scale.

Yes.

No.

Look, I mean there's -- I think maybe the earlier answer I gave is that we're now looking at this dynamic portfolio in terms of swaps, checkerboarding, other options we may look at, but they've all got to be managed within the financial frame.

And on that basis right now, we would have to find some of the source of funds.

Hence, why I've said we'll probably go beyond the $10 billion on the disposal packages to create more space within the balance sheet to look at other optimization opportunities as well as buybacks as well as dividend.

We'll take the next question from Bertrand Hodee at Kepler.

Bertrand?

I have one left.

Brian, you hinted for 5 final investment decision already taken this year.

Can you remind us which are those 5?

And can we expect more FID before year-end?

And especially, can you give us an update on the potential full-field development on Tortue, in Mauritania and Senegal?

Wow.

Okay.

Now you're testing me.

So from memory, and as somebody tries to scamper to get them, Atlantic Phase 3, we -- Atlantis Phase 3, we've done Seagull.

We've done, which is with Neptune Energy, Azeri Central East.

We've done Thunder Horse expansion.

South expansion Phase 2 is done.

And I think we've got one more to come, which I think actually now it's India KG-D6 is also done.

So they are the 5 FIDs that we've looked at this year.

And then in terms of Tortue, I think there'll be more to follow it -- follow on that at the full year.

But we've sanctioned the first Phase 1 FLNG auction and would expect -- we're expecting 2 additional phases which will start to significantly improve the economics around that.

And of course, I know you will have seen early this week Kosmos announced a discovery around Orca.

We haven't yet proved that up yet.

It's still early days from our perspective.

But Mauritania and Senegal, there'll be a lot more to follow on that at the full 4Q full year results.

We'll take the final additional third question going against the rills, Chris, a question from Chris Kuplent at Bank of America.

Are you trying to be nice to Chris?

I am in fact being nice.

I've given up trying to be nice to Chris.

But that's okay.

Let's get through your pieces of pain.

Quick final questions.

And you've changed slightly your full year CapEx guidance.

Is that partly reflecting what you already said about the Lower 48 as a number of those ramp-ups are now looking more like 2020 ramp-ups or any other efficiency news that you're keen to let us know about the lower end of the $15 billion, $17 billion frame?

Yes.

Thanks, Chris.

Actually, that's a good question because we didn't pick up on that, so thanks for highlighting it.

It's -- we're probably -- we're trending below the middle of the range, so we're actually below $16 billion right now.

We actually have backed off a little bit in Lower 48 as we're getting more capital discipline.

Capital discipline remains one of the -- and it will remain because I've had the conversation with Bernard already.

It will remain one of the key foundations of this company going forward, so we will keep a tight handle on capital certainly over the next couple of quarters.

And that's why you're seeing the number trend down.

It is systematically now trended down in the Upstream for the last 9 quarters.

Capital continues to come down.

And a lot of that is driven by a lot of the technology that Bernard has talked about that's been -- getting deployed in the Upstream.

But there's a huge opportunity for us in that space.

And so therefore, assume that trend continues into next year around capital.

And part of it is around the Lower 48.

But we don't want to start the Lower 48 with too much capital because there's a huge opportunity for us especially at these oil prices.

But our capital inside Lower 48 is still over $2 billion this year, so we're still making sure that we're not ranging $2 billion to $2.5 billion that we set aside for Lower 48.

And then thanks for asking that question, Chris.

It's an important one that we didn't pick up on.

Great.

With that, thank you for your time.

It's been a pretty busy quarter.

I think you will agree from the numbers that we've shared with you, it's a -- given what we thought -- we always thought the first half of this year was going to be very difficult to get through.

And actually, 1Q and 2Q were good quarters.

The third quarter has actually come through stronger than we'd anticipated, helped somewhat by oil trading, availability in Downstream and Rosneft.

But nevertheless, it has given us confidence in terms of future cash flows and the momentum we can see.

And we have a very large project that we've talked about before called Raven, which is due to come on at the end of next year, which will ramp -- around the end of this year, sorry, which will create further momentum and ramp up into next year.

I think the suspension of the scrip you should take as a positive signal now in terms of where we are, recognizing that gearing is still over the 30%.

But nevertheless, net debt has stabilized.

But we are committed to deleverage our balance sheet, and we are committed to finishing up the buybacks that we said that we would do irrespective whether the divestment proceeds came in.

And of course, as I said at the start, we're now, of course, into the CEO transition from Bob to Bernard.

I think it'll be a smooth handover of the baton.

And you will see a lot more and hear a lot more from Bernard in the first quarter as we come out with that transition beyond February and then later into the second half of next year out to 2025 strategy.

So with that, thank you very much for taking the time this morning, and we look forward to speaking to you on the road and on the next call.