英國石油 (BP) 2017 Q2 法說會逐字稿

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

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

Hello, and welcome.

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

I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley; and our Chief Financial Officer, Brian Gilvary.

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

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

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

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

These documents are available on our website.

Thank you.

And now over to Bob.

Thank you, Jess.

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

Today, we are here to report on our results for the second quarter.

The environment continues to challenge us, at the same time, it's been another quarter of solid operational delivery in all of our businesses.

In the Upstream, we are safely and efficiently executing on our suite of major project start-ups for the year, and the Downstream is showing resilient performance while also bringing on growth.

Most notably, it has been another quarter of solid underlying operating cash delivery for the group of $6.9 billion despite the weaker environment.

On an organic basis, we were able to balance our sources and uses of cash this quarter.

For today, I'll start by looking in more detail at the environment, and we'll also look at how the plans we have in place are fit and flexible to respond to the continuing uncertainty.

As usual, Brian will take you through the detail of our second quarter numbers and a reminder of our financial frame and guidance.

I'll come back to update you on our Upstream and Downstream businesses before we take your questions.

So starting with the macro.

After a stronger start of the year, Brent oil prices declined in the second quarter.

Continuing high inventories and recovering production in the United States and Libya put pressure on prices, despite the extension of the OPEC production cuts to the first quarter of 2018 announced in May.

Looking over the course of the year, demand for oil is expected to remain robust and increase by an above-average 1.5 million barrels per day this year, supported by continued recovery in GDP growth and supported by sustained lower oil prices.

At the same time, non-OPEC supply, after declining last year, is expected to increase by 700,000 barrels per day this year, driven largely by the recovery in U.S. tight oil production.

Compliance among the OPEC and non-OPEC countries participating in production cuts remains strong, and we expect this to continue at least through the period of agreement to March 2018.

Putting this all together, OECD inventories appear to be declining, moving us towards a more balanced position, although there remains a lot of uncertainties around the timing of that and around the longer-term outlook.

It is a tough environment and it could remain that way for some time, but we're building a business that is resilient to these changing conditions, we're operating effectively and we are advancing the strategic plans we laid out to you in February.

That means we're getting back to growth and securing our future over the longer term.

The foundation for everything we do is a relentless focus on safe and reliable operations.

You will always hear us talk about that.

Keeping our people and operations safe remains our top priority and #1 value.

It also underpins our growth plans and supports the delivery of reliable and sustainable cash flow.

Across the group, we expect strong growth over the next 5 years.

In the Upstream, we are on track to add more than 1 million barrels per day of new oil equivalent production by 2021 from 2016.

Around 800,000 barrels per day net to BP is expected to come from our major projects by the end of the decade, with an additional 200,000 barrels a day coming from our recent portfolio additions.

Our new projects should deliver on average 35% better operating cash margins compared to the base portfolio in 2015 and around 20%, on average, lower development costs.

This makes us increasingly resilient to the environment as we look to move the portfolio even lower down the cost curve.

In the Downstream, we expect to see more than $3 billion in sustainable underlying earnings growth by 2021 in addition to the $3 billion improvement delivered since 2014.

We laid out our strategies for marketing and advantaged manufacturing in some detail at our recent Downstream Day in June, where we illustrated the differentiated and very competitive drivers of future value in this business.

So I am confident in the plans we have set out to deliver disciplined growth.

Before Brian takes you through a reminder of our financial frame, I want to briefly emphasize a few key points.

First is that we continue to maintain a strict focus on capital and cost discipline; that is essential in everything we do.

Second, we are changing the way we think about how we operate.

We've come a long way over the last few years to become simpler and more streamlined, and we continue to learn from others, including outside our industry.

And third, we are making big strides in modernization, implementing digital and cutting-edge technology across our businesses.

We need to do all of these things well to ensure we remain competitive in any price environment, and I'm confident that the steps we are taking will be enduring into the future.

So with that, let me hand it over to Brian to take you through the results.

Thanks, Bob.

Turning to the environment.

Brent crude averaged $50 per barrel in the second quarter compared to $54 per barrel in the first quarter of 2017 and $46 per barrel a year ago.

The recent price movements reflect increased production from Libya, Nigeria and the United States, moderated by the extended OPEC production cuts.

Henry Hub gas prices averaged $3.20 per million British thermal units in the second quarter compared to $3.30 in the first quarter and $2 a year ago.

The global refining marker margin showed seasonal improvements.

The second quarter averaged $13.80 per barrel compared to $11.70 per barrel in the first quarter and $13.80 per barrel last year.

Turning now to the results for the group.

BP's second quarter underlying replacement cost profit was $680 million, around 5% lower than the same period a year ago and 55% lower than the first quarter of 2017.

Compared to a year ago, the result reflects higher exploration write-offs and a lower contribution from oil supply and trading, partly offset by higher Upstream liquids and gas realizations and higher Upstream production.

Compared to the previous quarter, the result reflects lower Upstream liquids realizations, higher exploration write-offs and the weaker contribution from oil supply and trading.

Second quarter underlying operating cash flow, which excludes Gulf of Mexico oil-spill payments, was $6.9 billion.

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

In Upstream, the underlying second quarter replacement cost profit before interest and tax of $710 million compares with $30 million a year ago and $1.4 billion in the first quarter of 2017.

Compared to the second quarter of 2016, the result reflects higher liquids and gas realizations, the impact of the Abu Dhabi concession renewal and higher production from major project startups, partly offset by higher noncash exploration write-offs, largely in Angola, and high depreciation, depletion and amortization.

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

Excluding Rosneft, second quarter reported production was 2.4 million barrels per day, 10% higher than a year ago.

After adjusting for entitlement and portfolio impacts, underlying production increased by 7% with the ramp-up of major projects.

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

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

Turning to Downstream.

The second quarter underlying replacement cost profit before interest and tax was $1.4 billion compared with $1.5 billion a year ago and $1.7 billion in the first quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $910 million in the second quarter compared with $1 billion in the same quarter last year and $1.2 billion in the first quarter.

Compared to a year ago, the result reflects continued fuels marketing growth, bringing the half year result to around 20% above the same period last year, and increased refining commercial optimization.

This was more than offset by a significantly lower contribution from supply and trading and higher level of turnaround activity.

Compared to the first quarter, the result reflects higher fuels marketing earnings and improved industry refining margins, largely offset by narrower North American heavy crude oil differentials and product mix impact.

This, however, was more than offset by a weaker supply in trading contribution and a higher level of turnaround activity.

The lubricants business reported an underlying replacement cost profit of $360 million in the second quarter compared with $410 million a year ago and $390 million in the first quarter.

The petrochemicals business reported an underlying replacement cost profit of $150 million in the second quarter compared with $90 million a year ago and $150 million in the first quarter.

In the third quarter, we expect a similar level of industry refining margins and that North American heavy crude oil differentials will remain under pressure.

Turning to Rosneft.

Based on preliminary estimates, we have recognized $280 million as BP's share of Rosneft's underlying net income for the second quarter compared to $245 million a year ago and $100 million in the first quarter of 2017.

Compared with a year ago, the estimate reflects a higher Urals price, partially offset by lower duty lag benefit.

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

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

In July, we received our share of the Rosneft dividend, which amounted to $190 million after all taxes.

This dividend represents 35% of Rosneft's IFRS net income for 2016.

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

In Other business and corporate, we reported a pretax underlying replacement cost charge of $370 million for the second quarter.

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

A nonoperating pretax charge of $350 million was also taken in the quarter, reflecting the latest estimate for Gulf of Mexico oil-spill claims and associated administration costs.

This is in addition to the ongoing unwind of discounting effects on the provision which have no impact on cash.

The adjusted effective tax rate for the second quarter was 60% and is higher than a year ago, mainly due to the Angola exploration write-off, which receives no tax relief, and the Abu Dhabi concession renewal.

In the current environment, we now expect the full year underlying effective tax rate to be tracking above 40% due to exploration write-offs in the first half of the year.

Looking next at cash flow.

This slide compares our sources and uses of cash in the first half of 2017 compared to the same period a year ago.

As Bob said, we balance our sources and uses of cash organically, as shown on the top right chart.

Excluding pretax oil spill-related outgoings, underlying operating cash flow was $11.3 billion for the first half, of which $6.9 billion was generated in the second quarter.

This includes a modest net working capital release of $110 million in the first half, with $1.4 billion in the second quarter.

Organic capital expenditure was $7.9 billion in the first half and $4.3 billion in the second quarter.

Net debt at the end of the quarter was $39.8 billion, and gearing was at 28.8%, within our 20% to 30% target band.

The increase was primarily due to Gulf of Mexico oil-spill payments, but we expect an improvement over the second half as payments decline and divestment proceeds come in towards the end of the year.

Now turning to a reminder of the key elements of our financial frame and our overall objective of growing sustainable free cash flow.

Starting with organic cash flows.

As we have seen this quarter, underlying operating cash flow is robust despite the lower trend in oil prices relative to the previous quarter.

This reflects a steady operational progress within our businesses and reversal of the first quarter working capital build.

With 3 of the 7 project startups planned for this year already online, we expect the ongoing execution and ramp-up of our project pipeline, along with ongoing underlying performance improvements in the Downstream, to continue to drive operating cash delivery for the group into 2018 and beyond.

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

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

Looking out to 2021, our overall capital investment plan remains unchanged from those we laid out in February.

We expect organic capital expenditure for the group to fall within a $15 billion to $17 billion per annum frame.

At the upper end, we would expect not to exceed $17 billion in any 1 year, and we will be very disciplined about that.

The lower end represents the ready flexibility we have to tighten capital expenditure during periods of lower oil prices without materially impacting our growth objectives.

So we would expect our capital expenditure for 2018 to be at the low end of the range should oil prices remain around $50 per barrel.

However, and I do want this point to be clear, this is not a floor.

To the degree that oil prices remain structurally lower, we will continue to drive capital efficiency towards a sustainably lower investment frame for the overall portfolio going forward.

Over the medium term, the underlying momentum in our businesses, coupled with the discipline in our capital frame, supports growing free cash flow for the group at oil prices well below where they are today.

And I will come back to that in a moment.

For inorganic cash flow, 2017 was always going to be a year with Deepwater Horizon payments heavily loaded to the first half and divestment proceeds to the back end of the year.

Deepwater Horizon cash payments were $4.3 billion in the first half and are expected to be between $4.5 billion to $5.5 billion for the full year.

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

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

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

Turning now to our progress in balancing the cash flows of the group.

Our aim has been to reestablish a balance in our financial framework where operating cash flow covers capital expenditure and the current dividend at the prevailing oil price.

In the first half of 2017, we made good progress in balancing organic cash flows.

Underlying operating cash flow after organic CapEx and cash dividends was $600 million in surplus at an average Brent price of $52 per barrel with broadly neutral working capital, so we were balanced comfortably below $50 per barrel.

So despite oil prices remaining unsettled, we have made strong progress in rebalancing our financial frame, allowing us to maintain our dividend with confidence.

Our balance sheet is resilient.

For the time being, we retain the option of scrip as an undiscounted alternative to our cash dividend, while continuing to target gearing within a 20% to 30% band.

At Brent oil prices below $50 per barrel, as already discussed, we would look to further optimize capital expenditure.

We have confidence in the group's near-term ability to recalibrate to sustain sub-$50 oil prices as we bring on strong growth in both our businesses.

Looking out to 2021, we expect our organic cash balance point to reduce steadily to around $35 to $40 per barrel, reflecting the material improvements in free cash flow expected in both the Upstream and the Downstream.

Beyond 2018, we expect organic free cash flow to start to grow in a constant price environment, supported by the further ramp-up of our new slate of Upstream project startups and underlying performance, coupled with strong margin growth in the Downstream.

Once surplus free cash flow is being generated, we would look in the first instance to address the dilution that arises from the scrip dividend alternative.

We will then aim to ensure the right balance between disciplined investment and distributions growth depending on the context and outlook at the time.

Let me now hand you back to Bob.

Thanks, Brian.

Let me briefly now update you on progress across our 2 main segments as it has been a very eventful quarter with more to come as we get into the second half of the year.

I'll start with the Upstream, and you will have heard us talk before about 2017 as a very significant year for BP.

This is proving to be the case.

We have already started up 3 of our 7 major projects for the year.

2 more are imminent.

We've made a lot of progress in resetting our cost base over the last few years, and we expect that trend to continue.

This year, we expect unit production cost to be more than 40% lower than in 2013.

Around 75% of these cost reductions are from efficiency, so these should be sustainable in the longer term.

Beyond this, we're pushing ahead with some really transformational changes as we digitize the business at pace.

This stretches from sub-surface modeling to wells construction to plant operations and all the way to electronic procurement.

We expect to deliver $13 billion to $14 billion of pretax free cash flow in 2021 based on our February assumption of $55 per barrel.

This is underpinned by 5% per annum average production growth, continued decline in unit production costs and improved capital efficiency.

Looking beyond 2021, we have improved both our capacity for growth as well as the quality of that growth.

We believe in the strength of our portfolio, which is balanced, increasingly competitive and positioned to reflect changing energy trends.

We always look to grow value and returns, not just volume, and we will deliver this through a continued optimization of our resources through our Area Development Planning process, the recent acquisitions as well as our modernization and transformation agenda.

Looking specifically at performance so far this year, we have maintained our discipline in operations while delivering effectively on the program of new projects.

As I just mentioned, 3 of our 7 major projects are already online.

In March, West Nile Delta, the Taurus/Libra projects in Egypt, started up 8 months ahead of schedule and with production 20% above plan.

In April, Trinidad onshore compression was delivered under budget.

And in May, we started Quad 204 in the North Sea.

This is a significant oil project, included the construction and installation of the world's largest harsh-water FPSO, the Glen Lyon.

Persephone off the coast of Western Australia is in the final stages of commissioning and is on track to come online in 3Q.

In Trinidad, the Juniper facility is progressing through final commissioning activities, and startup is expected in the coming weeks.

That leaves 2 more for 2017, and we remain on track to have Khazzan Phase 1 in Oman and Zohr in Egypt online by the end of the year.

We continued to see strong operating performance on our operated assets this quarter.

We completed 1 turnaround in the first half, and preparations are under way to start 4 turnarounds in the third quarter.

As for production, excluding Russia, this quarter, it was 10% higher than the second quarter of 2016, driven by the extension of the ADCO concession in 4Q 2016 as well as the startup of our major projects and good underlying performance of our assets.

And our unit production costs were 18% lower in the first half of 2017 compared with the same period in 2016.

This year, we've also had 4 significant discoveries, which support the strategic shift we are making.

Results from the Savannah and Macadamia exploration wells offshore Trinidad indicate an estimated 2 trillion cubic feet of gas in place to underpin new developments in these areas.

Also, in offshore Senegal, BP, along with joint venture partner, Kosmos Energy, announced in May a major gas discovery at the Yakaar well.

This well further confirms our belief that offshore Mauritania and Senegal is a world-class hydrocarbon basin and marks an important step in building BP's new business in this important region.

Looking out to 2020, our major projects are a significant part of our growth wedge to the end of this decade and beyond.

The 800,000 barrels per day of new projects production by 2020 is firmly on track, with the portfolio under construction ahead of schedule and around 15% under budget.

You will see the impact of our 2017 major projects towards the back end of the year, with production ramping up as we go into 2018.

During the second quarter, we sanctioned the R-Series deepwater gas project in Block KG D6 off the east coast of India.

This is the first of 3 planned projects in the block that are expected to be developed in an integrated manner.

We've also sanctioned the Angelin offshore gas product in Trinidad.

Looking further ahead, we have a strong portfolio that we continue to optimize and test against our hurdle rates, and that gives us a lot of options, with only the best and the most competitive going forward to FID within the discipline of our capital frame.

So we've made a lot of progress already this year in the Upstream.

We're right on course with where we want to be with the execution of our current set of projects.

And we're progressing in a very disciplined way with our plans for future growth.

Now turning to the Downstream.

I'll start with a reminder of some key messages Tufan set out as part of the recent Downstream Investor Day.

The disciplined execution of our strategy is delivering results.

$3 billion of underlying earnings growth has already been delivered in the 2 years since 2014, and plans are in place for more than $3 billion of further growth by 2021.

Growth is expected to continue to come from our marketing businesses, which are differentiated and high-returning, and our strategy is to grow these businesses in important global markets.

We also expect further growth from manufacturing, where we continue to build a top-quartile refining business and improve the cash break-even performance of our petrochemicals business.

Efficiency and simplification remain central to earnings delivery.

Cash costs in 2016 were some $3 billion lower than in 2014 and at their lowest level in more than 10 years.

And we continue to focus rigorously on cost management and efficiencies.

Taking all of this together, we expect to deliver between $9 billion and $10 billion of pretax free cash flow, with returns of around 20% in the Downstream in 2021.

The chart on the left side shows the detail of where we plan to deliver more than $3 billion of future earnings growth.

And you can see it is expected to come from all businesses.

Each of our Downstream businesses are differentiated, and it is their sources of competitive differentiation which underpin our detailed growth plans.

And by expanding our earnings potential, we will also further improve the resilience of the business.

You can see from the right-hand chart how we have already made significant progress, materially reducing the refining margin required to deliver Downstream pretax returns of 15% over the last 2 years and how our plans will improve this even further.

In a changing world, our strategy is building a Downstream business, which is fit for now and the future.

Now turning to progress so far this year.

We continue to grow underlying earnings in both marketing and manufacturing, with continued strong delivery against the strategy.

In fuels marketing, earnings have grown by around 20% in the first half of 2017 compared to 2016.

We've continued the rollout of our convenience partnerships model, with around 90 sites added so far this year.

And premium fuels volumes have grown by 7% year-on-year.

In Mexico, we were the first international oil company to enter the fuel retail market since deregulation, and volumes across our sites have more than doubled during the first months of trading.

And in India, we signed a memorandum of understanding with Reliance Industries to jointly explore options to develop differentiated retail and aviation fuels, mobility and advanced low-carbon energy businesses.

In lubricants, we secured a new agreement to become the exclusive premium lubricants brand retailed by Kroger, the largest supermarket chain in the United States.

We also successfully renewed our strategic partnership and supply agreements with a number of major vehicle manufacturers.

And in manufacturing, underlying earnings have grown in both refining and petrochemicals during the first half of the year.

In refining, we grew the value of commercial optimization compared with last year and increased the level of advantaged feedstock processed in the U.S.

In petrochemicals, following the upgrade at our Cooper River plant in the U.S., our industry-leading technology is now operational at all our key PTA sites.

And we also delivered record production levels at our plant in Zhuhai, China, during the first half of the year.

So in Downstream, we have a clear strategy which we're executing well.

You can see this in the results across our marketing and manufacturing businesses, and I'm confident we will continue to see further growth into the future.

So to briefly summarize.

In February, we laid out a very clear strategy for building resilience and competitiveness today, along with growth plans that are highly responsive to the changes that are taking place in the longer-term picture for global energy.

These plans are in action, and we have seen this in the solid operational delivery in the first half of 2017.

We're building a track record of strong and reliable operational performance.

We are right on track with a really busy program of projects in the Upstream, and we have real momentum in all of our Downstream businesses.

And we are maintaining our capital discipline as well as the focus on bringing our costs down in a long-term sustainable way.

So we believe we have an investment proposition that works in the near term and over the longer-term horizons.

All of this supports our principal aim of growing sustainable free cash flow and distributions to shareholders over the longer term.

On that note, thank you for listening, and we'll now open it up for questions.

(Operator Instructions)

Thank you.

And good morning, again, everybody.

We do have a long list of callers this morning.

(Operator Instructions) And of course, IR will be available for follow-up after the call.

We'll take the first question from Irene Himona of SocGen.

Are you there, Irene?

I had 2 quick questions, please.

Firstly, on asset disposals.

Brian, you reiterate the $4.5 billion to $5.5 billion by year-end.

I wonder if that refers to sales to be announced or actual cash receipts.

And have you announced some disposals that have yet to close this year?

Secondly, just very quickly on DD&A, it's up about 11% in the first half.

I wonder if the $8.6 billion is representative of the annualized charge.

Irene, so on disposal, it's proceeds, so it will be cash in this year.

We've already announced over $2 billion if you take into account SECCO.

It's probably about $2.5 billion in terms of announced deals.

And there's a whole suite of other small medium-sized transactions that will close in the second half of the year.

So the actual range we've laid out there of the $4.5 billion to $5.5 billion is still well-underpinned.

On DD&A, I'll have to come back to you on that specific question.

But in terms of effectively what we've got coming through so far this year is the new projects coming on stream and, therefore, we start to activate DD&A around those assets.

It will pretty much flatline from where we are if you look on a DD&A per barrel basis for this year.

It will probably flatline over the next 2 or 3 years as we look at the growth projects coming on stream and assets coming off the books as we go through some disposals.

But we'll come back to you on the specifics of DD&A and what the track looks like for the rest of the year with IR later.

Thanks, Irene.

And turning next to Christyan Malek of JPMorgan.

Two questions, just very quickly.

First, you previously mentioned if oil remains low, sort of in the low 40s, that your CapEx can be as low as $14 billion.

In light of your cautious view that oil is likely to trade within a range of $45 to $55 next year, your continued efficiency drives and improved cash margins on new projects, do you think there's more scope to reduce group CapEx without necessarily sacrificing sustained CFFO beyond 2020?

And the second question, sort of coming back to oil prices, to Bob.

You've outlined an oil price view for next year.

Is it fair in saying that's your view in the long term too or do you see things reverting higher?

Just interested to know how you think the trend sort of continues through the back end if you could.

Maybe just on the capital frame, what we've laid out is the $15 billion to $17 billion range.

I think for next year, I mean, Bob will come on to the oil prices, but I think we probably see oil prices firming through this quarter as we see demand continuing to grow.

That will probably taper off in the back end of this year.

So I think a range for next year around $45 to $55 seems like a reasonable assumption today, but a lot could change between now and the end of the year around supply and the demand side of the equation.

But in terms of capital, assuming we're around $50 a barrel for next year, then we'd be at the low end of our capital range.

And if we saw a prolonged period down at $45 a barrel, we could go below that $15 billion, which is what we've laid out in today's results, and we continue to believe that.

We're seeing more capital efficiency come through.

You've seen a strong set of cash flows in the first half of the year if you take out -- or then, basically, it's pretty neutral working capital for the first half of the year if you add the 2 quarters together.

That gives you a pretty good indication of the strength of the cash coming through and, therefore, more flexibility as we go forward.

And we'll continue to see capital efficiency and focus on costs and productivity throughout the organization.

And, Christyan, when you look at the supply and demand and the projections out there, I think Brian used the term $45 to $55 for the next year.

In our thinking, that's pretty good fairway for us going forward.

Thinking about $50 oil for the next 5 years is the numbers we're going to use right now and keep the discipline about it.

That will bring down the cost structures even further in the industry.

The U.S. shales are a swing producer.

There's always geopolitical events that could be -- create spikes in the other direction.

But in terms of our thinking, getting BP to work, getting our breakevens well into the 30s and thinking of it as a rough $50 over the next 5 years is right now our thinking.

We'll move next to Lydia Rainforth of Barclays.

Are you there, Lydia?

Two questions, if I could.

Just going back to, Brian, on chart -- or the chart on Slide 17 around the free cash flow cover of the dividend, if I remember rightly, at the 1Q stage, that was shown at $55 real and it's now shown at $50 to $55.

Is the interpretation of that chart, just so I'm clear, that the business will be breakeven sub-$50 a barrel next year?

And then the second one was just sort of in terms of the confidence in the numbers and the projections going forward, when I sort of add up all the projects and things like that, it does look that the numbers are very much risked and that there is potential upside within that.

Can you just comment on sort of how much confidence or sort of how much risking there is actually in that process?

Lydia, so, I mean, second part of the question, we risk all of those projects.

And I think as Bernard laid out when we laid out the strategy at the end of February, it implies 5% growth.

And, of course, those projects are risked across the piece and similarly, with the Downstream, as you saw from the Downstream Investor Day.

And they're risked for a reason, to sort of say, if you sort of take the middle of the fairway that Bob described, then that's what we think the outcomes will be, and there's lots of things can move up and down around that range.

On the move from $55 real to $50 to $55, so well-spotted, and you saw that in the first half of the year, we came in cash breakeven, was actually below $50 a barrel.

We still have to offset the scrip going forward, so that's still important for us in terms of next year.

And then in terms of where we're targeting cash breakeven next year will be a choice as to where we set the capital.

We'll continue to see more come through, I think, in the way of costs and capital efficiency that Bob laid out.

And as we land our plans for next year at the end of this year, we'll ensure that we set things up to make sure that we are balanced next year, ensuring that we also cover the scrip going forward and make sure that we can offset that on a go-forward basis.

But there's a lot of moving parts between now and the end of the year.

But you're right to pick up directionally our break-even price is moving down quicker than we may have anticipated at the start of the year.

And first half year is good progress, but there's still an awful lot more to do in the second half.

Thank you.

We will take a question now from Anish Kapadia of TPH.

First question is on Macondo.

If I look at the balance sheet, you've got a current liability on the balance sheet of about $3 billion.

So I just wanted to check, does that mean you'll have around $3 billion of cash out over the next 12 months from Macondo?

Or are there other offsets or further charges to think about?

And I suppose just how the kind of PSC settlement works into that?

The second question is relating to your U.S. midstream.

I know you're limited in terms of what you can say on that, but I just sort of wanted to kind of think about the bigger-picture strategy on examining the potential IPO.

Why are you looking at kind of going down that route rather than outright asset sale as I believe the majority of your assets are non-operated?

Okay, Anish.

On the Macondo liabilities, that would be the current liabilities, which would be typically 12 to 18 months out.

So you're right to say that that's the right order of magnitude, which we've laid out for you already, which actually, you can also imply from the ranges we've given you of $4.5 billion to $5.5 billion for this year.

We continue to expect to stay in that range and around $2 billion for next year.

So I think that all sort of box balances.

And we took a small increase in the provision as we start to see the wind-down now in terms of final suite of claims in the facility, and we expect the bulk of those claims to be dealt with in terms of determinations through to the end of this year and into next year and the sort of final payments to go out next year by the end of '18.

And then we'll be left with a suite of things on appeal.

In terms of midstream MLP, Bob, do you want to just pick up where we are on the MLP?

Yes, Anish, like you say, we can't say very much about it.

But I think, fundamentally, versus the sale versus an MLP, these are assets that are important to BP to optimize our operations around the U.S., the pipelines, refining.

And so by maintaining management interest in it, it's a lot better than just an outright sale, which could damage our optimizations.

We will move next to Theepan Jothilingam of Exane.

Two questions on Upstream.

Just could you talk about Khazzan and what's on the critical path in terms of commissioning and then ramp-up?

What's the sort of speed of the production increase we should expect from Oman, please?

Second question, just on the U.S. Lower 48 gas business, could you perhaps talk about where you are in terms of sort of cash generation?

Are you cash flow neutral at these positions and the progress you're making there in terms of taking out costs?

Theepan, the Khazzan project is moving along very well.

You'll know we've got a 60% working interest in there with the Oman Oil Company.

Our latest estimate for startups should be by October, overall progress in the project is up around 99.8%.

We've got gas that is filling the plant now.

It should be about 7 Tcf of unconventional gas.

We've got another agreement to expand it by 50%; takes it up to another 3.5 Tcf.

First gas, we can't really give the date today, but we've notified the government that we expect it to be in third quarter.

Our forecast for production this year are up around 17,000 barrels a day this year, and we'll be up well over 100,000 barrels a day next year.

Plateaued production will be 1 Bcf a day gross.

So we are feeling very good about the progress of the project, and just stay tuned on that.

Theepan, then on Lower 48, for last year, we were cash breakeven below $3.

And for first half of this year, we're cash breakeven below $3.

So therefore, at $3 an MMBtu we'd be generating cash.

Thanks, Theepan.

Turning next to Alastair Syme of Citi.

Brian, you've historically shied away from talking around divisional tax rates, and we get some disclosure on the Upstream from the [Anglo] filings.

But can you talk around what the portfolio activity will do to that Upstream tax rate when we see the full year accounts for this year?

And secondly, you've highlighted the WTI, WCS spread in the quarter.

Can you give us some sort of ballpark sensitivity on how that spread impacts on your Downstream earnings?

Yes.

On tax rates, I mean, it is -- there is a whole suite of inputs that come into that depending on where the oil price is, depending whether it's PSA, PSE, particularly from a corporate perspective in terms of deferred tax losses that we carry forward, what's happening with foreign exchange rates.

So therefore, it's actually not that easy or straightforward to try and give you an indication of what's happening in terms of overall rate.

But I think guidance for the year for the corporation, this year we're probably tracking now above 40%.

And remember, we move from around 30%.

The range previously was around 25% to 35%.

With the [ADCO] concession, we moved the effective rate up to 40% because of the high tax barrels that come through with that.

On that basis for this year, we're now tracking above 40% given the exploration write-offs that didn't attract any tax relief this year.

So we're now tracking above 40%.

Cash tax rate, Alastair, would typically track around 6% to 10% below that historically.

So -- and actually, for the first half, it's about 8% below.

But other than that, I'm afraid I can't give you any much more information.

In terms of WTI, WCS, as you'd expect, as prices come down, that differential narrows in.

Also, with some of the disruptions up in Canada and producer outages, we've seen that, effectively, that spread has come in.

We've talked historically about wanting something around the mid-teens is where the big Whiting investment around the upgraders came.

If the level gets too low, you start to run more WTI than heavy.

But I think you'll start to see the spread open up a little bit, which we've seen recently, but we're not expecting a major recovery as we come through this year, and it'll really be driven by pure supply and demand economics coming out of Canada in terms of heavy crude.

We don't actually give an indication in terms of what that means on a rule-of-thumb basis.

And so really, that's all I can say about WTI, WCS.

Thanks, Alastair.

Next up, Jason Gammel of Jefferies.

I wanted to ask, first of all, about how you think about leverage relative to the relief of the scrip dividend.

Just recognizing that we're now getting pretty close to your 30% ceiling on the end of the quarter and recognizing that divestiture proceeds will pull that down, but is there any level of leverage that you would want to reach before really for the scrip dividend once you get into a position where you're generating significant free cash flow?

And then my second question is a fairly quick one, I hope.

I've lost my decoder ring, Brian.

I was hoping you could tell me the absolute magnitude that is associated with significantly lower supply and trading contribution.

Jason, thank you.

And I'm sure if somebody can do an algorithm with machine learning, you'll probably be able to work out these results from all the various things we've said over the last 10 years.

On the first piece, gearing, net debt, that's not really -- it doesn't cause us any issues in terms of offsetting the scrip, so that wouldn't be a determining factor in our discussion to offset scrip.

And we're only talking something -- at today's levels, offsetting scrip is around $1 billion to $1.5 billion, so it's not a huge amount in the overall scheme of things.

And certainly, the balance sheet could more than absorb that.

So the balance sheet will not form a determining step in offsetting scrip.

It will be like being back into cash surplus on an organic basis will be the biggest driver of that.

So that is not a cause for concern and certainly would not come into the equation.

Even at 30%, there's still quite a lot of flexibility we've got on the balance sheet, and 30% isn't the ceiling for that range.

It's more about long-term financial framing guidance, so it's always possible to go through it, although I don't anticipate that will happen given the strong cash flows we've seen in the first half of the year.

Supply and trading overall, gas and oil is tracking to plan so far this year.

Oil trading had a stronger first quarter than second quarter, but actually, we had a first half, it's tracking just at around about plan and is bang on the historical 5-year average.

So there's no major issues with 2Q other than the fact it was weaker than 1Q, and it was weaker than what was a strong 2Q last year in comparison.

So that's the decoding for you.

And other than that, I can't give you any more specifics.

Thank you, Jason.

We'll go now to Gordon Gray of HSBC.

Two quick ones, please.

Firstly, on Deepwater Horizon payments.

If I recall, the non-fine portion of it, the majority of it is tax-deductible.

But although you're generating profits at the moment in the U.S., the pre- and post-cash tax cash outflows are the same.

Can you talk about how much of a tax shield, let's say, is still outstanding from Deepwater Horizon payments and how that may work its way through?

And the second one was just one about the R-Series fields in India.

Just if you can give us a feel for the clarity you have and, if possible, some more detail on the pricing of the gas that gives you confidence in the long-term returns from that project.

Yes.

So in terms of the tax credits off the back of Deepwater Horizon, the majority of those have been booked.

A number of them have already cleared their way through the system, if you think now we're sort of year 7 beyond where we were in terms of the original provisions that were taken.

And the only increase, the only credit for the tax charge will be what's been taken for this quarter associated with business economic loss claims that we laid out for you in the results.

So that continues to work its way through our annual results.

And as you say, as we start to see the U.S. come back into profit, you'll see those credits start to work their way through.

But a number of those credits have already worked their way through the system over the last 6, 7 years.

And as India said that they want to increase their share of gas 20% domestically, we're in -- with the new contracts, market rates that put us, well, probably the price will vary a little bit quarter-to-quarter, but in the $6 to $7 area for the pricing.

With the FIDs that we've put in place and the reengineering and retooling and the cost of the developments come way down, they've moved way up in our prioritization.

We're starting out with the first phase.

We've got 2 more behind it after the R-Series.

One is in D55 field, which is deep below the KG-D6 platform itself.

So these projects are looking very good right now, and there's a lot of government support for these things to come on.

Thanks, Gordon.

Turning next to Thomas Adolff of Crédit Suisse.

Got 2 questions as well and going back to CapEx, if you don't mind.

Firstly, in terms of capital efficiency and productivity, the levels you have reached today, do you think it is harder to go much further at a steady oil price?

And what I'm interested in is further capital efficiency, including as well as excluding the benefits from automation, big data, et cetera, things like where we are -- where are we on the standardization process?

And in the context of that, what is assumed in your 2021 targets?

And secondly and perhaps also indirectly linked to the first question, you said your CapEx guidance represents a hard ceiling and a soft floor.

But in the context of the soft floor, how low can you go before you start to starve the business of capital?

And how does it compare at a steady oil price environment, again, in 2018 versus 2021?

In 2021, you have much higher production.

So maybe just to start with, Thomas I think if Bernard were here, he'd tell you in terms of longer term, he's looking to position that division and business to ensure that it's robust at $45 a barrel.

And no doubt we may well see those sort of levels again over the next 12 months.

So I think there is more capital productivity to come through from all the area you just laid out.

I think you'll remember at the end of February, Bernard talked about all the modernization and technology advancements that we're making.

You'll have seen some announcements in the press around things that we're doing.

They will inevitably lead to more capital productivity, which we're seeing right across other sectors.

And number of things we've been early adopters of, we're now starting to bring into fruition, which you saw some of the things Bernard talked about at the end of February.

So there is more to come in that space.

In terms of the short term, because really, we're only talking the next 12 months out in terms of flexibility in the frame to the downside, there's probably about $1 billion of capital to the downside if we saw a prolonged period of $45 a barrel over the next 18 months.

I suspect that will not be the case, but nevertheless, we will have plans in place to make sure that we can deal with that and ensure that after, effectively, giving ourselves 3 years to get the company back into balance after that 4-year period of $100 a barrel, then I think it's right that next year we will be back in balance.

And, Thomas, I'll just add on the Upstream, the technologies that are not fully built into our cost estimates that will transform new developments will be the transformation we'll see in drilling.

Automated drilling will come in.

The use of sensors and automation and all across these developments will undoubtedly lead to productivity increases that we haven't yet fully built in.

In terms of starving the business for capital, I think it's always going to be the discipline.

We have more opportunities than we can actually pursue going forward.

So we'll just try to get that balance right to make sure we continue the growth without starving the business of capital, but really driving that efficiency into it.

Thank you.

And we'll turn next to Rob West of Redburn.

The first one is just a bit of clarification on Page 21, where you talk about major projects ahead of schedule, which I think is the title of the slide.

I was wondering.

Is that referring to some of the startups this year where the ahead of schedule-ness has already been announced in press releases?

Or looking down that list, are there any in '18 or '19, '20 that are coming in ahead of the milestones you've set out for them along the way?

So that was the first question.

And the second one was just going back to what Anish asked you about, the extra provisioning for Macondo.

I'd just like to understand a little bit better what is mechanically happening where those extra charges need to be taken?

I don't know if you can give us more detail on what actually changes quarter-to-quarter where you have to take those extra charges, so we get a sense of whether any future charges might be sensible for us to kind of put into our numbers as well.

Rob, a couple of things.

In terms of major projects ahead of schedule, these are some of these schedules we'd laid out quite some time ago of Thunder Horse South, which came on last year, was far ahead of schedule and under budget.

Of course, we've seen West Nile Delta come on this year.

Zohr which was originally an 2018 project, now will come on in 2017, of course operating with Eni.

Khazzan at one point was an '18 startup.

It's now getting close, so we've narrowed it back down.

If you look ahead to 2018, I'll just pick a couple of projects.

I think Atoll, the first phase in Egypt, has potential to be ahead of schedule.

It's not inconceivable it could come on before the end of this year, but probably first quarter next year.

That's moved fast, very quickly.

Phase 1 of Shah Deniz, the delivery of gas into Turkey, that's moved up, sort of targeting I think probably [eight] October next year.

And then Maersk is operating Culzean, which is -- we've seen that move up as well.

So those are just a few on those lists.

And, of course, these -- our schedules change all the time, of course.

As we get further into the engineering, we can see it and be more precise.

But I think the execution of our major projects team over the last 4 years has been quite remarkable and a transformation from the phase that we were in before.

And then in the terms of Deepwater Horizon, it's really around the runoff of the final piece of the claims facility.

There was a recent ruling in the court which has led to -- if you remember at the very start of this process, we had about 149,000 claims in that facility.

We're down to 5,000.

There's been a recent court ruling, which majority-wise, underpin a number of other rulings we had, which has helped in terms of proceeding going forward.

But it's also in -- effectively resulted in the recycle of about 2,000 of the 5,000 remaining claims to go back through the process which is deferring things out, which means admin costs are slightly higher and a redetermination around some of those claims as a result.

So hence, that's what -- -- why we've pushed through this extra charge.

Effectively, we're expecting everything to be done by the end of next year.

There's a slight 12-month delay to the runoff in the final piece of the claim, but we don't believe it will have a cash impact this year, and it will have a minimal cash impact next year.

Thank you.

And we'll take a question now from Jon Rigby of UBS.

Can I speak -- ask you about the Downstream?

I mean, you invested a lot of time and effort in presenting to the market on the Downstream about a month ago, with quite a differentiated bit of disclosure and discussion around the separate businesses that go into the Downstream.

And you talk about some of the progress today, but the disclosures that you're giving are very traditional, one might say, somewhat old-fashioned.

And I think, as you acknowledge, the trading result this quarter sort of emphasizes the volatility in that business.

So wouldn't it be better or has some thought been given to expanding disclosures, to talk about some of the progress in the underlying subsegments around the conversion of sites and other progress that you're making to emphasize progress made in the Downstream, with what are quite ambitious earnings and cash flow targets?

That's the first question.

The second is, Brian, you talked about the use of cash as and when you move to cash surplus and you talked about the balance between the antidilution of the scrip and CapEx.

You didn't mention debt, and I wondered whether over the longer term, given what's happening in the market, given obviously volatility in oil prices, the impact of shale, et cetera, whether there's been any consideration taken around sort of lowering through-cycle net debt as and when you can.

.

So maybe, Jon, on the second part of the question, our average cost of borrowing is just over 2%.

So I mean, just to put that into context, that -- if the -- it's not that expensive to carry that level of debt and again, you'll recall during the Macondo period of uncertainty, we moved the range down to 10% to 20%.

But no, that's -- if anything the push of investors is actually 30% is pretty comfortable, couldn't you go higher?

So I'm not -- net debt is not one of the issues that's sort of on the agenda in terms of now.

It will naturally decline over time as we go forward and debt rolls off.

We'll have choices as to whether we want to renew that debt, depending on what the prevailing rates are, but right now, economically, it's actually -- it's not a bad a place to be in terms of where we are.

So that doesn't cause any cause for concern.

On Downstream, I think over the last 4 years, we've done a lot of disclosure.

You've got sub-segmentation of the fuels business, we show you lubricants, we show you chemicals, so you've got access to those.

I think the Downstream Investor Day, Tufan laid out a lot of information, which again, you'll see the disclosures, we talk about the number of new sites that we've added so far this year.

I think it was something, I think, around the order of 90 new sites.

We have the Woolworths transaction, which is in the sort of regulatory phase in terms of approvals going through.

And what we're doing on the communities partnership side.

We also gave you some indication around trading inside the fuels business, as you alluded to, in terms of volatility.

But we'll take on board your comments and we'll sort of talk with Tufan about whether we can give you more disclosures going forward.

But you will start to see the underlying improvements come through that we saw over the last 2 or 3 years and what we've laid out to 2021.

You'll get a lot more information around that going forward.

Thanks, Jon.

And the next question will be from Martijn Rats of Morgan Stanley.

I have 2. I also have a question on Slide 21, which is the exhibit that shows your major projects over the next couple of years.

Altogether, it adds up to 800,000 barrels a day of oil equivalent production.

But if you focus on the projects that are oil, as far as I can see, they add up to about 85,000 barrels a day of that total, so a smidgen above 10%, suggesting that the other 90% is gas.

Now I know the mix is shifting and that the strategy is sort of moving, but is that really the strategic intent of BP to have the oil-gas mix shift so much towards gas over the next couple of years?

And the second question is related to the Russia Sanctions Review Act.

I have to say I struggle to really understand how much this means or what it could mean, but perhaps could you give us your view of what it will mean for BP if this was passed in its current form?

Right, thanks, Martin, both good questions.

There is a shift in the portfolio to gas.

It's not a 90% shift.

We do have the oil projects in there.

If you look at the Thunder Horse Expansion projects, you've got the Mad Dog project, which is a significant oil project coming down the track; Clair Ridge next year in the U.K.; Quad 204 this past year.

And then with a fair number of these gas projects, there's a lot of liquids and condensate with it.

So I think the number isn't 90%.

These projects, we look at as advantaged gas projects.

They're not like Lower 48-type projects.

They tend to be in markets that are short gas where we have contractual gas pricing so that the economics are clear.

The Egypt projects fit into that, the Oman projects fit into that.

So there's gas and there's gas, and so these are quite selective gas projects for us.

In Mauritania and Senegal which has -- will have a significant amount of gas, I'd also add that there's a lot of oil prospectivity there as well, which wouldn't be on the charts.

But it is, you've seen our strategic shift.

We will -- low-cost oil, advantaged oil will still remain a very important part of the portfolio, but a shift higher to gas.

On the Russia sanctions, we've noticed that there were -- the language in the version that went into the House was full of unintended consequences, for example, that might have affected the Shah Deniz project, even some of the Egyptian projects.

As I understand it, the language has been rewritten into all that, that now avoids those very, very significant unintended consequences to American companies.

The sanctions themselves, as they're written, and we'll carefully monitor this and, of course, we have to work very carefully within the sanctions, but we're not aware of any material adverse effect on our current income and investment in Russia or elsewhere or our ability to work with Rosneft itself.

We stay away from targeted individuals, of course, and don't get involved in any of their personal business.

But we've been able to work well within the guidelines for the last 3 years, and these new ones don't appear to change that.

Thanks, Martijn.

And we'll go now to Michele della Vigna of Goldman Sachs.

I was wondering over the next 12, 24 months, which projects you felt comfortable enough to FID and where you think that more work could still further lower the costs from here.

Well, we've deferred a couple of FIDs, you'll know, in Pike and in Browse, for good reasons.

We could see ourselves with an additional FID in Atlantis Phase 3, a very significant oil development in the Gulf of Mexico.

The costs are coming down.

That's clearly got great prospectivity there.

That's one I would think about.

We've got another one in the Gulf of Mexico we may consider.

We need to work with our partners on that.

You might see us with additional FIDs down the road here with -- in India, we said we've sanctioned the first one with the R-Series, but there's others in India.

And we've just recently sanctioned Angelin in Trinidad.

So we'll pace these out.

We'll be very selective about them, but we've got some good projects there that you don't see on the list on Slide 21, which -- and I'd also add, some of those are oil.

Thank you, Michele.

Next question, from Iain Reid of Macquarie.

A couple of questions, please, one on Senegal and Mauritania.

Just wondered how the recent discovery, Yakaar, has changed in any way the planning that you've got for developments there.

Is this going to kind of change the focus from the talk to discovery?

I wonder if you can give us an update on what you're planning at the moment in terms of FID on that project?

And second question, Bob, just coming back on this Russia issue and just perhaps a bit more philosophically.

The dividend from Rosneft has now fallen below $200 million per annum and it looks like it's not going to move very much from that given the outlook for oil prices.

I'm just wondering how you feel about the return on the investment from the significant amount of money you've got invested in Rosneft following the dissolution of TNK-BP, and whether that really -- whether the strategic upside which you keep talking about really compensates for the very low return you're getting from that investment.

Yes, Iain, thanks.

On Mauritania-Senegal we had that significant discovery South of Tortue in Senegal, whereas Tortue is on the line between Mauritania and Senegal.

We're drill stem testing a well right now in Tortue.

I think this is such a prospective region now.

We see resources there.

If we look at it, I think there's probably 50 Tcf of gas out there in Mauritania and Senegal.

The development concepts, I think will be modular in a way that we'll be able to -- we need to appraise this and then we'll optimize it.

We have a development concept now for Tortue, but we can alter this depending on discovery of other resources out there.

We'll be drilling some wells in Mauritania, the Hippocampe project in Requin Tigre this year.

All of those things could change our thinking in terms of what could be a fairly complex resource area and maybe even further in the North in Mauritania, there's some oil.

But I think what that discovery essentially does, it just demonstrates the high potential of that basin itself.

So I would stay tuned with that.

It's all good news.

We'll see what happens on the DST and these other wells that we're planning to drill this year.

On the Rosneft dividend, by the way, there will be an Extraordinary General Meeting of Rosneft in September where they'll begin to declare dividends twice a year.

So it's always been 1 year -- dividend once a year.

We'll see another dividend payment in the fourth quarter.

I'm reasonably sure that's the outcome from the voting.

Rosneft is a 5 million, 5.5 million barrel a day company.

It has lots that it's doing to make itself more efficient.

The Russian government is reviewing their tax system because it was basically put in place at $100 oil.

I still believe it has lots of upside potential.

It, like BP, is working to get its break-even costs down.

And so I think it's doing exactly strategically the things any company should be doing at these oil prices, and I still remain hopeful that we'll see improved profitability from them.

But I think this step of going to a dividend twice a year based on half-year earnings and then looking at the portfolio, the tale of the portfolio is all positive.

Okay.

Can I just say -- could I just ask, any update on the timing of FID for Tortue?

Well, no, not with the DST going on now.

I think that's part of the -- part of it is just to appraise it further.

But we've done a lot of engineering work with Kosmos, and we'll be able to move pretty fast on it.

But no, I can't give you a date right now.

Thank you.

We'll take a question now from Chris Kuplent of Bank of America.

My 2 questions are as follows.

Firstly, Brian, you once again referred to the $2 billion to $3 billion annual disposal rate that we should expect from 2018 onwards.

Is that a net number?

Or should we assume that proceeds generated will partly cover ongoing oil-spill payment costs, and at the same time be reinvested in external growth, the likes of Zohr and Mauritania that we've seen over the last few quarters?

And my second question would purely be for a clarification.

You said you've announced $2.5 billion of disposals so far this year.

Can you already tell us how much cash flow those assets have generated in the first half so far?

So on the second question, Chris, the difference, it's $800 million of proceeds have come in, in the first 2 quarters and the difference is, of course, SECCO which is due to close by the end of this year.

It will be the delta between those 2 pieces.

And then on the $2 billion to $3 billion, that -- I mean, it's not that they will cover in any 1 year.

But -- so effectively over time, what we've said disposal proceeds will cover, Deepwater Horizon payments and inorganics.

And for next year, actually, that will be the case.

So something around $2 billion to $3 billion will cover $2 billion of Deepwater Horizon payments that are currently forecast for next year if you look at the schedule of payments to come out and where we think the claims facility is.

And the balance will be inorganics in terms of cash payments in 2018, so that's correct.

I'm sorry, Brian, for SECCO in the first half in terms of cash flow that you've still consolidated in terms of run rate?

In terms of proceeds or in terms of the earnings from the asset?

Underlying earnings.

No, so the cash, that is consolidated inside the numbers in the first half of the year, and that will only be deconsolidated when the transaction closes, once it goes through regulatory prudence in China.

And in the first half, there would have been a few -- couple of hundred?

We don't do cash numbers by sub-asset.

We [actually don't], that you'd expect, Chris, but there is a significant amount of proceeds to come with the closing of that transaction in the second half of the year, around $1.7 billion was the full consideration.

Thank you, Chris.

And we'll take the last question now from Biraj Borkhataria of RBC.

I had a couple.

So firstly, in the Lower 48, the data you provide shows that the costs of -- or the operating costs have gone up for the last couple of quarters.

I was wondering if you could talk a little bit about the underlying trends you're seeing there.

And then secondly, back on FIDs, I just want to get a sense of how you're thinking about this going forward.

One of your peers has talked about 2017 being a window to lock in, bottom of the cycle further costs.

You don't seem to be in as much of a rush.

So I was wondering if you could talk a bit about what you're seeing maybe on the offshore market or any commentary there.

On Lower 48, it's nothing more than phasing of where we are in terms of the various programs.

We obviously have a choice in terms of what we're doing in the drilling space each quarter.

So it's quarterly noise that you can see coming through those numbers.

But the long-term focus continues to remain on making sure that we continue to drive efficiencies and costs through into that business and what we're learning from the various activities that we've done that we laid out for you last year.

And Biraj, on the FIDs, you're right.

Well, some of the competitors are saying '17 is the year to lock it in.

We have been locking in some of the low yard spaces and contracts for the FIDs we've done in '16 and '17.

Not convinced that this is the low point, particularly in the offshore and offshore drilling, for example, where I think there's such a big oversupply that you can expect to see drilling costs come down.

So it's not clear yet, that we have to rush to lock these in.

Thank you, Biraj.

And I think that's the last of our questions.

So thank you very much, everybody, for helping us run a more efficient call today, and I'll just hand back to Bob to -- for closing remarks.

Thank you.

Thank you, Jess, and thank you, everyone, for listening today.

It is quite a bit shorter, it may not feel like it, but it's been quite a bit shorter this quarter than the other quarters, which is absolutely based on your feedback.

I'll just say in February, we laid out a strategy for where we were heading, getting our business readjusted for the new price environment.

And we need to build a track record.

This is only the second quarter out of the 20 quarters that we laid out then.

So we'll just keep coming back, snapshots as we move forward on this.

I think we've delivered pretty well on this quarter and particularly as you know, we really drive our business for cash, and that's the most important number that I think comes through on this quarter.

So thank you all very much.

See you next time.