英國石油 (BP) 2016 Q3 法說會逐字稿

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

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

Hello and welcome.

This is BP's third quarter 2016 results webcast and conference call.

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

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

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

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

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

These documents are available on our website.

Thank you and now over to Brian.

Thanks Jess.

Welcome everybody and thank you for joining us.

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

As you have seen, the environment remained volatile over the quarter and continued to impact quarterly earnings across the sector.

Outside of the environment we had some mainly one-off and non-cash items impacting our upstream result for the period, while our downstream delivered strong underlying earnings.

Most notably, it has been another quarter of robust underlying operating cash delivery for the Group.

This clearly demonstrates the resilience of our business operations to the current environment and the impact of our ongoing work to reset the Company.

We remain confident in the progress we are making to reestablish the balance in our financial frame and reposition our businesses for today's environment.

We will begin by looking at the macro, then cover our third quarter numbers in detail, before updating you on our financial frame and the progress we are making towards rebalancing in 2017.

We will finish up with a brief update on our businesses before Jess and I take your questions.

So looking first at the oil market, our view on the fundamentals remains largely unchanged.

The physical market appears to have moved broadly into balance, with the amount of oil produced each day broadly in line with daily consumption.

Nevertheless, oil inventories are at record levels and will still take some time to reduce.

Looking ahead, we expect inventories to decline gradually next year, supported by continued demand growth and sustained weakness in non-OPEC supply.

The precise pace and timing of that decline will depend on the outcome of OPEC's meetings at the end of November.

Forward prices for Brent continue to point to a modest upward trajectory.

The forward curve moved slightly higher in October following OPEC's announcement.

Looking more specifically at the price environment for the third quarter, Brent crude averaged $46 per barrel in the third quarter, which was largely flat compared with the second quarter.

Oil prices fell in July as oil inventories reached a new high, but improved again towards the back of the quarter on improving fundamentals, further supported by the newly stated intentions of OPEC.

Henry Hub gas prices recovered in the third quarter, averaging $2.80 per million British thermal units.

This is well above the average of $2.10 we saw in the second quarter.

Prices have responded to a combination of declining production and increased demand from gas-fired power generation, which in the third quarter was at a record level in the United States.

Looking forward, rising seasonal demand should support some firming in Henry Hub gas prices.

The third quarter global refining marker margin averaged $11.60 per barrel compared to $13.80 per barrel last quarter and $20 per barrel a year ago.

High product stock levels continue to keep refining margins under pressure, with OECD product stocks at their highest level in 30 years.

Looking ahead, we expect a stronger outlook for both oil and gas prices to support improved realizations in our upstream businesses into next year.

We expect refining margins to recover from the current low with modest improvement next year, but still well below the very high margins of 2015.

However, we are building resilience across the downstream where refining margin volatility only impacts around half of the segment's earnings.

The balance comes from our marketing related activities where we are experiencing continued growth.

Turning now to the results, BP's third quarter underlying replacement cost profit was $930 million, down 49% on the same period a year ago and 30% higher than the second quarter of 2016.

Compared to a year ago, the result reflects significantly weaker refining margins and lower liquids and gas realizations, partly offset by continued lower cash costs across the Group and a one-off tax benefit arising from changes to UK supplementary taxation.

Compared to the previous quarter, the result reflects the one-off UK tax benefit and stronger underlying performance in our downstream, partly offset by lower refining margins and higher upstream rig cancellation charges, exploration write-offs, and various one-off items.

Non-operating items in the third quarter, which amounted to a gain of $950 million after tax, included net impairment reversals relating predominantly to assets in Angola and the North Sea.

Third quarter underlying operating cash flow, which excludes Gulf of Mexico oil spill payments, was $4.8 billion.

The third quarter dividend, payable in the fourth quarter of 2016, remains unchanged at $0.10 per ordinary share.

In upstream, the third quarter underlying replacement cost loss before interest and tax of $220 million compares with a profit of $820 million a year ago and a profit of $30 million in the second quarter of 2016.

Compared to the third quarter of 2015, the result reflects lower liquids and gas realizations, lower gas marketing and trading results relative to a strong result in the same period last year, and higher rig cancellation charges and exploration write-offs, partly offset by lower costs, reflecting the benefits of simplification and efficiency activities.

Excluding Russia, third quarter reported production versus a year ago was 5.9% lower.

After adjusting for entitlement and portfolio impacts, underlying production decreased by 2%, mainly due to seasonal turnaround and maintenance activities and the impact of weather and the Pascagoula plant outage in the Gulf of Mexico.

Compared to the second quarter, the result reflects stronger market prices, offset by weaker gas realizations outside of the United States, and lower midstream revenue, higher exploration write-offs, around $200 million of charges specific to the quarter, including higher rig cancellation costs and various other one-off adjustments, and the impact of Gulf of Mexico production downtime.

These were partly offset by continued underlying improvement in cost efficiency and stronger gas marketing and trading results.

Looking ahead, we expect fourth quarter reported production to be slightly higher than the third quarter, mainly reflecting recovery from planned seasonal turnaround and maintenance activity.

Turning to downstream, the third quarter underlying replacement cost profit before interest and tax was $1.4 billion compared with $2.3 billion a year ago and $1.5 billion in the second quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $1 billion compared with $1.9 billion in the same quarter last year and $1 billion in the second quarter of 2016.

Compared to a year ago, this reflects a significantly weaker refining environment and a higher level of turnaround activity, partly offset by increased retail performance and lower costs from simplification and efficiency programs.

Compared to the second quarter, the result reflects a weaker refining environment, partly offset by increased retail performance and lower turnaround impacts.

The lubricants business reported an underlying replacement cost profit of $370 million in the third quarter, compared with $410 million in the second quarter and $350 million a year ago.

The petrochemicals business reported an underlying replacement cost profit of $80 million compared with $90 million in the second quarter and $40 million a year ago.

In the fourth quarter we expect increased turnaround activity compared to the third quarter, and industry refining margins to continue to be under pressure.

Turning to Russia, based on preliminary estimates, we have recognized $120 million as our estimate of BP's share of Rosneft's underlying net income for the third quarter, compared to $380 million a year ago and $250 million in the second quarter of 2016.

Our estimate of BP's share of Rosneft's production for the third quarter is just over 1 million barrels of oil equivalent per day, an increase of 2.7% compared with a year ago and flat compared with the previous quarter.

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

In July we received $332 million as our annual dividend.

This represents 35% of our share of Rosneft's IFRS net income in 2015, an increase from the 25% payout ratio in prior years.

In other business and corporate we reported a pre-tax underlying replacement cost charge of $260 million for the third quarter.

The average quarterly charge for the first nine months of the year is $270 million and is in line with guidance.

The underlying effective tax rate for the third quarter was a credit of 23%.

This includes a one-off deferred tax benefit from the reduction in the rate of a supplementary charge in the United Kingdom announced in March.

Excluding this one-off benefit, the underlying effective tax rate in the third quarter was 37% compared to 39% a year ago.

The reduction in the rate is mainly due to foreign exchange effects and changes in the mix of profits.

Turning to the Gulf of Mexico oil spill costs and provisions, the total cumulative pre-tax charge for the incident is $61.8 billion or $43.5 billion after tax.

As previously disclosed, following the substantial progress we have made in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill, our first half results incorporated what we believe is a reliable estimate of all the remaining material liabilities in connection with the incident.

The charge for the third quarter now mainly reflects the unwind of discounting effects on the provision, which has no cash impact.

Going forward, you would expect to see a similar amount unwinding each quarter.

Moving to cash flow, this slide compares our sources and uses of cash in the first nine months of 2015 and 2016.

Underlying operating cash flow, excluding pre-tax oil spill related outgoings, was $4.8 billion in the third quarter and $13.3 billion for the first nine months of 2016.

Third quarter underlying operating cash flow included a working capital release of $700 million, reversing the build in the first quarter.

Gulf of Mexico oil spill payments were $5.1 billion for the first nine months and third quarter cash outgoings of $2.3 billion included $0.9 billion for the first scheduled payment under the 2015 settlements.

Divestment proceeds amounted to $2.7 billion for the year so far, including $800 million in the third quarter.

This includes $570 million from the partial sale of the Group's shareholding in Castrol India for the first nine months, of which $270 million was received in the third quarter.

Organic capital expenditure was $11.5 billion in the first nine months and $3.6 billion in the third quarter.

We estimate that the cash impact of non-operating restructuring charges has been $900 million so far this year, with around $1.9 billion incurred since the fourth quarter of 2014.

We expect the impact to be approximately $1 billion for 2016 as a whole.

Now that brings me to the main components of our financial framework over the medium term.

We now expect capital expenditure to be around $16 billion this year compared to our original guidance of $17 billion to $19 billion.

In 2017 we continue to expect spending to be between $15 billion to $17 billion, but leaning more towards the lower half of this range as we continue to improve capital efficiency.

This represents a 30% to 40% drop in capital expenditure by 2017 compared to the peak levels in 2013.

The Group's controllable cash costs for the last four quarters are now $6.1 billion below 2014 levels, and well advanced towards our $7 billion cash cost reduction target for 2017 compared to 2014.

This rebasing of costs represents strong progress towards our objective of rebalancing organic sources and uses of cash by 2017 at average Brent oil prices in the range of $50 to $55 per barrel.

This in turn supports our ongoing commitment to sustaining the dividend as the first priority with our financial framework and restoring growth in distributions to shareholders over the longer term.

We continue to expect $3 billion to $5 billion of divestments in 2016 and around $2 billion to $3 billion per annum thereafter in keeping with historical levels.

The proceeds from these divestments provide additional flexibility and cover for our Deepwater Horizon payment commitments in the United States.

We also continue to manage gearing within a 20% to 30% band.

At the end of the third quarter net debt was $32.4 billion, with gearing at 25.9%.

Looking ahead to 2017, our aim, as noted, is to reestablish a balance in our financial framework where operating cash flow covers capital expenditure and the current dividend in a $50 to $55 a barrel price range.

This retains the dividend at a level we believe is supported by the long-term cash-generating capability of our underlying businesses, without damaging our growth objectives.

The environment has been tough but we have seen robust cash flow delivery from our operations year to date, despite the very weak environment in the first quarter and the impacts of recent downtime due to seasonal maintenance and weather.

This reflects the structural efficiencies increasingly translating into cash delivery in our businesses.

Relative to 2016, we expect 2017 operating cash flow to benefit from improved environment that would add an incremental $2 billion to $4 billion to cash flow.

We also expect to see the full cumulative benefits of our cash cost reductions as we approached our $7 billion target.

Non-operating restructuring charges are now expected to continue through 2017 as we continue to focus our organization, but we expect the cash flow impact to reduce relative to this year.

As we move through 2017, we also expect operating cash flow to be supported by growth and continued underlying performance improvements in both our businesses.

With oil prices likely to remain unsettled for a while yet, we will continue to judge our cash outgoings according to the environment, including optimization of capital expenditure and taking further advantage of deflationary opportunities if oil prices remain below expectations.

In short, we will work to balance at the prevailing oil price.

Any take-up of our scrip as an undiscounted alternative to our cash dividend provides an additional source of flexibility near term.

Looking further out, we expect our balance point to continue to move lower, driven by continued focus on cost and capital efficiency across the Group, and the growth in our businesses.

Growth in our upstream is expected to be a function of our planned new projects, bringing on material new volume as well as delivering on average 35% better operating cash margins than our base assets today at flat oil prices.

Once rebalancing is achieved, and based on our current portfolio, free cash flow is expected to start to grow at prices similar to where we are today.

In the first instance, we would look to address the dilution that arises from the scrip dividend alternative.

We will then aim to ensure the right balance between disciplined investment for even stronger growth and growing distributions to shareholders over the longer term.

Now turning briefly to the highlights from our businesses.

Starting with the upstream where we continued to see strong operational performance.

Plant reliability has been 95% across our operated assets year to date, and we have completed all nine of our turnarounds on time.

We also saw strong drilling performance in the quarter, with drilling and completion non-productive time at around 20%, down from 31% over the same period last year.

During the quarter, we created Aker BP along with our new partners, Det norske.

This innovative venture combines the strengths of both companies, bringing together Det norske's streamlined operating model and our technical skill, international experience and knowledge of the Norwegian sector of the North Sea built up over many decades.

This quarter we also sanctioned the Trinidad onshore compression project, which represents our third final investment decision this year.

We also completed and installed the first platform jacket for Shah Deniz phase 2, marking a significant milestone for the project, which is on schedule for the first gas in 2018.

We are on track to start up five major projects this year, with four of these projects already online, and In Amenas compression on schedule to start up in the fourth quarter.

A further eight major projects are on track for start-up in 2017.

Looking out to 2020, more than 90% of the 800,000 barrels of oil equivalent per day of new production that we expect to bring online has passed through the final investment decision and have either been completed or are well under construction.

We are also making significant progress in exploration by shortening our cycle time from discovery to production on some of our latest discoveries.

Our Nooros discoveries in Egypt were on production two months after discovery, and Kepler 3 came online within 11 months of discovery, which is faster than typical Gulf of Mexico developments of this scale.

In Egypt we made two further exploration discoveries in the Messinian and signed a number of concession amendments which will continue to encourage further investment in this region.

We also signed a second production sharing contract for shale gas exploration in the Sichuan Basin, with China National Petroleum Corporation.

This builds on the successful cooperation we are already seeing with the previously announced agreement signed earlier this year.

Our progress this quarter shows our effort to drive efficiency and productivity is supporting strong operational performance, while we continue to lay the foundations for future growth.

We are finding creative ways to generate more value from our focused and balanced portfolio, and we are building a business model in the upstream that is sustainable in a $50 per barrel world.

We are focused on growing value, both now and in the future.

In the downstream, we continue to deliver strong underlying performance improvement, helping us to mitigate the impact of the weak refining environment.

Our refining operations have continued their year-on-year improvement with Solomon availability for the year standing at 95.4% compared to 94.4% for the same period last year.

We are continuing to grow profitability in our marketing businesses.

Across our retail businesses, volumes have increased by 3% year to date, and we have also entered into two new strategic convenience partnerships in Europe, further strengthening our retail position in these markets.

In lubricants, pre-tax earnings have grown more than 7% so far this year, reflecting continued progress in our growth markets and premium brand performance.

We are also leveraging our technology capability to develop differentiated products.

This quarter we launched Castrol Magnatec with dual-lock technology, a lubricant which provides 50% more protection from stop-start engine wear.

In petrochemicals, we launched a new low carbon brand of PTA which, through our proprietary technology, supports around a 30% lower carbon footprint than the average European PTA production.

And lastly, we have further progressed our simplification and efficiency agenda.

Cash costs to the end of the third quarter are now 25% below the same period in 2014, demonstrating strong progress towards delivering the downstream target.

So the downstream has material and growing marketing businesses and continues to deliver underlying performance improvement in our manufacturing operations.

Together this gives us both resilience to a range of market conditions, and of course opportunities for further growth.

To sum up, we are confident in the Group outlook going forward.

As Bob said last quarter, it's all about sticking to a clear set of principles that work in any environment.

It requires us to operate safely and to make sound value-based decisions about our portfolio as we maintain discipline over our uses of capital.

And it requires us to sustain and drive continuous improvement into our cost base as we work to position ourselves competitively down the cost curve.

It's about resilience, sustainability and growth.

In our upstream growth is imminent and visible to the end of the next decade.

As we laid out in Baku, we expect our upstream to drive material growth in free cash flow for the Group over the medium term, even at oil prices where they are today.

And we are making careful choices to ensure we remain competitive longer term.

An example of this is our recent decision not to participate in exploration of the Great Australian Bight.

In the downstream we have a high-performing business model with good resilience to the environment, ongoing opportunities for growth and relatively low capital intensity.

We expect this business to similarly continue to contribute material and growing free cash flow for the Group.

The environment is moving slowly towards a more balanced position, but we are not relying on this going forward.

Our plan is to execute effectively to bring on growth, while sustaining discipline on capital and costs.

You will have heard our upstream refer to this as making it stick.

This will steadily bring us into a balanced cash position at the prevailing oil price.

In the meantime, our balance sheet remains sufficiently resilient to deal with any ongoing volatility.

Near term, this translates in our financial frame to rebalancing organic sources and uses of cash by 2017 at $50 to $55 per barrel.

This allows us to sustain our dividend, while still investing enough to grow long term.

Looking further out, our primary objective remains to grow sustainable free cash flow and distributions to shareholders.

Thank you for listening and we'll now open up for questions.

(Operator Instructions).

Welcome back everybody.

We would like to take the first question from Oswald Clint at Bernstein.

Are you there Oswald?

Yes, hi.

Thank you Jess, good morning.

Maybe the first question Brian just on the US onshore gas business with gas prices up at closer to the $3 level in the third quarter.

Can you talk about the underlying profitability of that business given you have such a large natural gas business there please?

And then secondly, maybe just following up on your comments on the restructuring continuing through 2017, perhaps you could explain why that has to continue for, I guess, another 12 months please?

Thank you.

Thanks Oswald.

In terms of Lower 48, we're now running about five rigs the last time I looked in terms of where the activity is.

We're continuing to reduce costs in that business, which is bringing the breakeven prices down.

The key is really about what we learn about technology and how we run the business.

We run it with a different financial frame to the rest of the Group in terms of how it's managed, and it is continuing, as you'll see from the various quarterly numbers that we now start to release, get to be more and more profitable going forward.

And of course, helped somewhat this quarter by the prices as the prices have come up.

So Lower 48, it really is about testing new zones, looking at innovative well designs.

It's really experimenting with that business and getting more comfortable with how we run the Lower 48 and reducing costs over time and the amount of capital that's going in.

But today it's running about five rigs.

I think the peak last year was around 11 or 12 we had at one point.

In terms of restructuring, we've extended it out to next year, mostly because of the activity.

As we've got more and more underneath simplification and how we're driving efficiencies into the business, we now can see that actually there's likely to be more restructuring into next year.

Very confident now around the $7 billion target.

We've talked about $6.1 billion at the end of this quarter.

I think we'll see further significant progress through the fourth quarter.

Very confident we'll hit the $7 billion for next year; we'll probably hit that early, and then it may well be that the costs go beyond that as we look at this next phase of restructuring programs.

Super.

Thank you.

Thanks Oswald.

We'll take the next question from Irene Himona at Soc Gen.

Thank you Jess.

Good morning Brian.

I had two questions please.

Firstly in Q3 your natural gas realizations outside the US appear somewhat weaker than anticipated perhaps.

Can you give us any guidance on how the portfolio outside the US is linked all-in versus Hub prices perhaps?

My second question, just if you can remind us on the Gulf of Mexico cash payment.

It was $2.3 billion in Q3.

What can we expect going forward as the annual or quarterly run rate into 2017 please?

Thank you.

So maybe just picking up that last question first.

We've got a schedule we've put out there from all the various settlements, from last year's 2015 and from the criminal settlements back in 2012.

So there are specific payments in certain quarters going forward, and I'm pretty confident that we've put that out on the website before.

So if we haven't got that to hand, we'll make sure that gets out to you Irene, but that's out there publicly available in terms of -- I think we did it in last quarter's results and the one before that.

The only uncertainly will really be around how the payments that go out associated with the class action lawsuit settlements, the PSC settlements, particularly business economic loss claims.

We are accelerating a number of those at the moment; you will have seen quite a few go out recently.

We also resolved a lot of private claims through the second and third quarter of this year, which you will have seen come out in the payment schedules.

They are likely to run down over the next couple of years.

So they're the only things where there's any uncertainty, but now we're into the final stages of that fund.

I think we're down to -- from the peak on business economic loss claims I think we had 144,000 claims at the peak, of which now we're down to 25,000 or 35,000 including the daughter claims, i.e.

claims linked to the original claim.

And they are being processed at a fairly rapid rate right now in terms of the facilities.

So there are a series of scheduled payments around settlements.

They're available, they should be on the website or we'll certainly get those to you.

Then the only uncertainty is really around what the phasing looks like around the class action lawsuit settlements and how that payment schedule goes down.

What I would say is in terms of how we're running the financial frame, they're being covered by our disposal proceeds going forward.

So to a degree this year we're already up close to $3 billion disposal proceeds.

Along with the proceeds from next year they will cover the bulk of the claims.

In terms of the forward [projectory] on Macondo liabilities, the lumpy years are this year and next year and then we get into the $1 billion a year, which is those future schedules which will be more like a dividend to the Gulf States out to 2030 or so.

On gas prices, a lot of our non-Henry Hub gas impacts come from Trinidad and Asia Pacific.

So it's really from the Tangguh developments, the Trinidad developments.

That's really where those realizations are coming from.

A lot of our new gas projects that you'll know that start up in 2017, 2018 and 2019 are linked to domestic markets.

So they won't be as exposed to that softness that we've seen in the LNG pricing outside the United States.

Thank you Brian.

Okay.

Next question from Brendan Warn at BMO.

Yes thanks.

Good morning Brian, good morning Jess.

Just a question if I can circle back to, I think it relates to slide 16, and you made comments about share buybacks or balancing your scrip.

Can you just talk through -- obviously if you assume prevailing prices -- can you just clarify that if by 2020 if we're still in prevailing prices, just in your mind what would be the trigger for share buyback?

Would you be comfortable to be able to move to, call it, mop up the extra scrip that's been issued?

And just in terms of how that ranks ahead of any further growth acquisitions please.

Thanks.

So once we get through 2017, we're now confident in terms of our plans that we'll be balancing at the prevailing oil price next year, let's assume around $50 to $55 a barrel.

But we're now confident that we'll get operating cash balanced up with CapEx and dividends for next year.

That looks pretty much within sight now.

So in terms of what we laid out for you earlier this year and at the back end of last year, we're confident we'll get there.

Once we get back into balance, then I think within the financial frame we've got full flexibility to look at other options, whether they be of an inorganic nature in the capital space, but certainly buybacks would come onto the radar screen.

To the degree that we have been issuing scrip, of course we would like to offset that.

We don't like to dilute our shareholders.

So when that opportunity arises, that's something we'd look at.

And it will really depend on where we are, where the prevailing market is.

You'll recall when we did the transactions around TNK and Rosneft, we bought back $12 billion of stock -- actually it was $10 billion; two tranches, $10 billion and then $2 billion.

So buybacks are definitely in the armory.

Obviously as we've gone through 2015 and 2016 it's been really focused about rebalancing with the big drop in oil price from $110 down to $28 at the low point.

So once we've got things back into balance next year, then buybacks will definitely come back inside the frame.

And it will be the broader frame of options around long-term sustainable dividend growth, buybacks and other potential inorganic opportunities that may arise.

Okay.

Thanks Brian.

Turning now to Anish Kapadia of Tudor, Pickering, Holt.

Morning Brian.

A couple of questions please.

The first one is on your cash flow.

Just trying to bridge where you are at the moment to the guidance for 2017.

So if I look at your Q3 cash flow, stripping out working capital and I suppose normalizing the Rosneft dividend in this quarter, it's about just under $4 billion I think for the quarter, so about $16 billion on an annualized basis in a $45 oil price environment.

Based on your breakeven guidance for next year, it suggests about $22 billion plus of cash flow in a $50 to $55 oil price environment.

So I was just wondering if you could bridge the gap between that $16 billion to the $22 billion plus.

Obviously there's some oil price in there, but what are the other elements that take you up to that level?

And then the second one.

In a sustained $55 plus environment next year -- I know you have your CapEx range but what's the short cycle CapEx opportunity that you have?

How much capital could you put to work in a $55 dollar plus and you say a strong gas price environment if the opportunity arose?

Thank you.

Okay, so on the first point, so that's actually not -- one, as I've already said before, even when we had the $32 billion target, never take a quarter times four, especially this quarter.

But broadly-broadly, you would look at the operating cash for this year; you would take out further costs that we would expect to come through at the back end of 4Q along with what else is to come out next year; you'd have the restructuring cash payments around [RatEx] that goes out this year that you wouldn't have to repeat next year.

So if you like, cash flow this year has a weight of payment associated with that RatEx, that $2 billion restructuring charge that we talked about.

And you've also got growth in margins and volumes to come through, along with, as you pointed out, the environment.

So if we look at the average oil price this year, I think it's been tracking around $42, $43 a barrel so far year to date, which is actually roughly in line with what we set our plans at for this year.

So actually we've been sort of tracking not exactly each quarter but year to date we're around where we expected to be in terms of the plan.

We expected some firmness around the fourth quarter.

We'll see what happens with OPEC at the end of this month.

But I think $50, $55 looks a reasonable assumption coming into next year, and we're confident that we can balance at those, which means that yes, you're right, the operating cash clearly would need to be north of $20 billion, given the CapEx range we've given you and given where the dividend is.

But we're confident that we'll get there, once you strip out the RatEx, the costs, additional volume and margin coming through.

We've got the big chunk of new projects coming on stream next year; we've got some more growth in our downstream around our fuels marketing businesses.

And we haven't assumed a particularly strong refining margin for next year.

So I think on balance we have a pretty conservative set of assumptions for 2017 in terms of balancing.

And then, coming back to your second part of the question, we've set a range on CapEx for next year.

We're now down at $16 billion for this year.

We're going to be sort of probably below that in setting our plans for next year in the $15 billion to $17 billion range, and then we'll know that at $50, $55 we'll get back into balance.

That means we've got about $1.5 billion of CapEx flex, which we'll be able to deploy as opportunities arise.

And those opportunities could be in terms of getting back to work on some of the onshore.

So the obvious place you'd look at would be Lower 48, as you've flagged up in terms of where the gas price is.

But that will be completely commercially driven.

And then of course there may be other opportunities for us where we can access existing positions that we have, where we can deepen, maybe go into some new areas.

So we've got some flex within the capital frame to allow us to do that, which will, of course, help with future growth beyond 2022, 2023.

Very helpful, thank you.

Thanks, Anish.

A question now from Lydia Rainforth at Barclays.

Good morning, two questions, if I could.

Brian, you were talking just in answer to Anish's question about the 2017 cash flow numbers and just from the commentary it does sound like you're fairly confident around that $50, $55 number.

Can you just talk about where -- are there any operational aspects in terms of risk that you're seeing around that?

Where are the challenges in terms of getting to that number next year from the operational standpoint?

And then secondly, just quickly on Rosneft and the deals that they've done, whether it's Essar Oil or Bashneft, how does that fit with BP's strategy within Russia?

Thanks.

Okay, Lydia, so I'll come onto that second question shortly, but in terms of assumptions for next year, of course, we need to make sure that all the kit is running as well as it's run this year.

Actually I'm not even sure whether reliability figures for next year may actually be slightly below where we are this year in terms of -- because we had a very strong year this year in terms of reliability and availability in downstream.

So we'll have relatively conservative assumptions for that for next year.

We'll need to make sure the projects come on time, on budget.

They're all proceeding incredibly well right now.

If I look at the oversight that Bernard and his team has on those projects, they're looking on track in terms of what we're expecting for next year.

So, of course, they would have to come on stream.

We'd have to continue to see the performance improvements that we've seen in downstream this year continue into next year and with a relatively conservative refining margin assumption.

So I'm not concerned that the plan feels overly stretched to get back into balance next year.

We set ourselves a target back in the fourth quarter of 2014 to give ourselves two years to get back into balance.

We're confident that we'll do that now, around the assumptions that we've laid out for next year and it will assume the oil price is around $50, $55 next year.

In terms of Russia, yes, you will have seen the announcements around Bashneft, which is an acquisition of one of the state companies in Russia, where Rosneft acquired 50.1%.

We'll, of course, consolidate that into our results as that transaction gets closed.

So that'll be about -- if you look at -- so from BP's perspective it will increase earnings, it will increase production, it will increase reserves and ultimately, given where our -- the dividend policy that we have with Rosneft, that will increase our dividend going forward, depending on where the earnings are off the back of Bashneft.

And then, of course, you have the strategic deal that Rosneft has done, Russia-India deal with Essar around their refinery, which I think gives Russia and Rosneft access to a very good market, which we like ourselves, India, in terms of a growing market on the retail side.

It helps Rosneft's trading arm going forward, and then I think there were some synergies for Rosneft around the Venezuelan crudes and moving that crude into the Indian refinery.

So I think it's a deeply strategic deal for Rosneft, it's one that I know Bob was back and forth to Russia, certainly in the last couple of months on numerous occasions with the Rosneft Board.

And I think it helps underpin Rosneft's global expansion into other markets around the world.

So I think in that respect it's good.

Our focus with Rosneft is really on the onshore, where you'll have seen we've announced recently the two new AMIs around Yermak, which are conventional exploration opportunities for us around two AMIs in Northwest and Northeast Siberia.

So that we're really interested in, which is a 49% position that we have.

Along with the Volga-Urals position and the Taas position, we're now starting to solidify our own position in Russia with Rosneft as BP with boots on the ground.

That's really helpful, thank you.

Over now to Jason Gammel at Jefferies.

Good morning, everyone, two questions from me please.

First of all, Brian, I apologize if you've made this explicit, but I've missed it if you have.

On the $50 to $55 breakeven price, does that assume that the entire dividend is paid in cash?

Or is there a scrip component of that?

And then the second question is on the fuels business on the quarter.

The flat result sequentially struck me as quite resilient, just given that refining margins declined in the quarter and availability ticked down slightly.

So can you help me to reconcile what the offsetting factors were there?

Is that simply stronger marketing operations?

And was there a contribution from the trading business in that result?

Yes, so on the first question, we set out that we would get things back into balance, including the full dividend.

Now, for next year the scrip uptake over the last -- since we introduced the scrip in 2009 it's been around about 18%.

It's been high this year which, of course, has helped our cash position, hence why we would be keen to be able to offset that dilution going forward as we get back into balance.

So the new financial frame we have is that operating cash needs to cover the full dividend, along with organic CapEx.

For next year, it's likely that we'll need some help from the scrip uptake, as we get through this transition of having a full year of all the costs and restriction charges out, which will be 2018.

But we're confident for next year on a cash basis we'll certainly get back into balance.

In terms of the downstream result, I think it just reflects all the work that Tufan and his team have been doing in terms of -- and we've talked about this in previous quarters, is how do we create resilience.

And there's a slide that Tufan has used on previous quarters that will show you how the refining margin has declined and yet how our earnings have increased over a period of time, in that what has been structured inside the business is that through the fuels marketing business and growing that business going forward, they've been able to create a balance within the overall portfolio.

Of course, coupled also with the lubricants and to a lesser degree, the chemicals business.

So half of the earnings coming out of the downstream now are not as exposed to that refining margin, which is what we laid out in our presentation.

So I think what you're seeing this quarter in downstream is the strength coming through that fuels marketing result in what was a relatively solid trading result for the quarter, but certainly nothing out of the ordinary.

So actually it really is coming through from the fuels business.

Very helpful.

Thank you, Brian.

Thanks, Jason.

Now from Jon Rigby at UBS.

Yes, hi, Brian.

Can I ask two questions?

The first is on the $6.1 billion cash cost performance, are you able to break that down a little bit and characterize where it's coming from?

I think from memory the downstream was ahead of the upstream in terms of contribution when we last revisited it.

So are you able to deepen a little bit on the analysis on that?

And the second is I know it's somewhat frustrating, I guess, for you, as everybody else is, where you take big non-cash exploration charges which hurt your earnings.

I know there's no economic impact, but as you wind down or normalize your exploration activity and go through the backlog of stuff that's still under appraisal, is there very much more to come in that?

Or will we start to see the exploration charge in the quarters begin to level out closer to the level of activity that you're actually now running at on a cash basis?

Thanks.

On the cost question it's actually neck and neck now, Jon, they're exactly the same.

So it's in the $6.1 billion, just over 40%, actually about 45%, has come out of the upstream, 45% out of the downstream and the balance out of corporate.

Now, of course, some of the corporate costs already sit in the two segments, but they're exactly the same in terms of the delta on the $6.1 billion.

There is still a big chunk yet to come through in the fourth quarter and into next year, which is really around the final upstream plans, but equally downstream have still have further restructuring plans in place.

So they're about the same in terms of sources and I think that's just symptomatic of how we've driven efficiency and reorganization across the whole corporation.

So it's no surprise that it's about the same, but you're right; previously it was more driven by the upstream than the downstream, but it's about 50/50 now.

In terms of the exploration piece, of course, because as we've gone through with the reset of the Company in the last couple of years, there is a big inventory of exploration intangibles that we're working our way through and you're seeing that come through.

If anything, it's actually reduced compared to the run rate that we were seeing only a couple of years ago.

There are still more decisions to be taken, we'll continue to do that on a point forward basis.

We'll try and give you more information around what that looks like around the fourth quarter results, but I can't at this point say we've reached a stable, steady state.

Ultimately everything gets back to strategy, it's really about how we've reviewed what we're doing around exploration strategy.

We're doing a lot less wildcats, there's a lot more focus now on the infield developments.

As a consequence of that, you'll see some of the decisions we've taken.

So the Great Australian Bight is a good example of -- ultimately that was not commercial for the Company and if we stacked it up in the portfolio of options that Bernard and his team were looking at, the Great Australian Bight simply didn't work and on that basis we've stepped away.

We're still absolutely committed to Australia, it's not about that location and indeed actually we announced a -- from memory, we announced a license around North West Shelf, new access position we've taken in the North West Shelf.

So it's really about how we now sift and sort the portfolio of options we have, and as a direct consequence of that, some things we'll view as not being commercial going forward.

And of course, they get taken through to underlying earnings in terms of exploration write-offs.

But I can't at this point, Jon, say where we are in the cycle, given the size of the intangible asset base that we still have.

Fair enough, thank you.

Thanks, Jon and we'll take a question now from Rob West at Redburn.

Go ahead, Rob.

I wanted to ask my first question about volumes.

You already alluded to this in your comments, but it wasn't a particularly normal quarter.

I was wondering, could you quantify if there's any disruption in the volumes say year-on-year that you expect to come back as we look to future quarters?

I note from the release that it might not come back in 4Q.

You allude to higher turnaround activity compared with the third quarter.

I just want to confirm is that right?

It sounded in your comments as if you said nine turnarounds had been completed and so I just wanted to confirm are there more still to come.

And finally, has anything changed in your mind about Alaska, the big LNG project there, just based on looking at it in the last quarter and some of your partners' comments?

Thanks very much.

On volumes, that's a really good point and so actually if you looked at this quarter, there were a lot of moving parts around the quarter on volumes.

I think we said underlying down 2%.

Actually if you take the Pascagoula outage that we had, which was over 20,000 barrels a day, weather impacts were just shy of 20,000 barrels a day, and then we had PSA in fact primarily around Iraq.

If you add all of those effects up they come to just under 130,000 barrels a day, which actually explains that delta.

So you wouldn't expect to see certainly the Pascagoula outage and weather repeat itself going into the fourth quarter.

Notwithstanding, I think we're now getting towards the end of the hurricane season, or pretty close to it.

So you're right; most of those effects won't repeat through future quarters, so that's why you'll start to see -- and the turnaround delta quarter-on-quarter, you'll start to see a little bit of impact of that.

On Alaska, we still have -- there's still 30 Tcf of proved resources up there in terms of gas.

Yes, I understand the most recent comments that some of our partners have made.

I think gas is a great opportunity for Alaska going forward and for those of us that have lived around and seen this project over many, many years, I'm sure it'll have more machinations going forward.

But there is nothing firm at this point in terms of where the point forward is in terms of that state and the resource base.

But it is a great resource base, it's discovered, we know it's there, it's being re-injected today.

I think the short-term economics make it difficult, but in terms of long-term resource, it may well be a great opportunity to bring to market, but right now nothing's happening.

Very clear, thanks.

Thanks, Rob.

Moving now to Theepan Jothilingam of Exane.

Thanks, Jess, good morning, Brian, so two questions please.

Could you just come back to -- I think you talked about the offsetting the Macondo cash outflows with disposals next year.

So could you just give us a little bit more confidence that can be achieved and essentially a bit of flavor in terms of where you see disposals, or disposal potential in the BP portfolio going forward?

And then secondly, just in terms of forward-looking growth, if you could give us a quick update on the two UK projects please.

Thank you.

Thanks Theepan.

So in terms of disposal proceeds, we've set a target this year of $3 billion to $5 billion.

We're already close to $3 billion at the end of the third quarter.

We have a number of projects in train that will comfortably get you to the $5 billion over an 18-month period, so some of those will flow into the first quarter of next year.

That will underpin two to three next year.

A lot of the projects we're looking at are midstream assets, it's some of our properties that we own globally.

You'll have seen that we announced the sale of our Sunbury assets, our property assets down in Sunbury recently, which have brought in significant proceeds.

So the proceeds side of this is well underpinned in terms of $3 billion to $5 billion this year, $2 billion to $3 billion next year and actually you only -- in terms of Macondo liabilities, the big lumpy years are this year, with the settlements from last year that originally transacted this year and the private settlements that we've managed to resolve, along with the payments next year.

And then we get into a steady state of $1 billion a year, so actually you only need about $1 billion, $1.5 billion of disposal proceeds beyond 2018 to cover it.

Although we'll probably continue to churn at $2 billion to $3 billion and a lot of that churn just comes out of looking at the portfolio.

As we take options to move certain commercial projects forward, other projects within the portfolio may have lower returns and therefore, we'll look to move out of those assets.

So there will always be a natural churn in our business, though it has been at $2 billion to $3 billion.

So absolutely confident that in terms of the $3 billion to $5 billion this year, $2 billion to $3 billion next year, that's pretty well underpinned.

And indeed, we're going to be certainly at the -- well we'll certainly hit the $3 billion to $5 billion this year and there'll be some of those proceeds will flow into next year, that will be towards the end of the $5 billion in the first half of next year.

So no problems on that side.

In terms of major projects, Quad 204, we're now 96% complete, with the latest estimate startup in the first half of next year.

Glen Lyon, you'll see -- I think we had a photograph of it actually on the presentation, the Glen Lyon is now in place.

It's got 14 new wells, 15 flow lines, 21 risers on it and it's designed to produce 130,000 barrels a day.

So that is all on track.

Clair Ridge facilities -- I actually wish Bernard was here with me -- facilities were 87% complete and we've still got latest estimate back end of next year 18%, we'll see where we end up with that sort of range.

And we've got new production facilities that come with Clair Ridge and these are great investments for the UK and the North Sea.

And I think it's really important about how we extend the life of the North Sea going forward.

I think these are major investments, they're a major commitment, certainly for BP in terms of the North Sea, and it's a great opportunity for us into the future.

That brings jobs, it brings work and it brings production and value to both the communities and to BP.

So both projects are tracking really well.

Thanks, Brian.

Okay, moving next to Thomas Adolff of Credit Suisse.

Morning, guys, I've got a couple of questions please.

Firstly, we're now just over two years into the downturn and we haven't really seen BP do many bolt-ons, unlike your partner, Rosneft.

So, Brian, are you surprised by that?

Particularly when we think about the comment you made at the end of 2014, I would have thought that BP would be a bit more active on bolt-ons.

Second question, I guess, on franchise assets, and I'm referring to assets that define a company.

Say for Chevron, it would be the non-royalty paying equity in the Permian, for Shell it might be the Santos Basin in Brazil.

What would it be for BP?

And maybe a final one, a very short one, what sort of reserve replacement ratio, excluding Russia, do you expect for 2016?

Thank you.

Okay, well let me take that last one first, because it will be too early to say that.

It really will be a function of the [FIDs] that we put through this year.

We've got three FIDs have gone through already, we have two more, one of which you'll all be aware of, around Mad Dog phase 2 which is coming up in the fourth quarter.

So where we end up in terms of the underlying reserves replacement, excluding Russia and our other entities, it's too early to say at this point.

So can't really give you an indication around that, but that really is the function of FIDs and what we end up with the reserves at the end of the year.

In terms of value options and bolt-ons, actually we've looked at a lot of activity.

We actually have bolted on one or two small things around the portfolio, we've actually deepened in some positions.

But I think the thing that we've looked at, as we've gone through last year and the second half of 2015 in particular, the valuations against some of the assets that we were looking at were simply too high.

And in some respects we come back to the previous question from Theepan, this really is not a seller's market for upstream and I think people's perception of the values they should be achieving are above what we would see as being economic, or would be accretive to the Company.

So I think we've always been clear; if a transaction is accretive and it's accretive to our shareholders, or it's deeply strategic and adds value into the long term for the Company, then absolutely you'll see us do those things.

And let's see what happens over the next 12 months, but I think there will be opportunities that we're looking at today, opportunities that will come up as people try and get their own balance sheets into order going forward.

And we will look to pursue those, but really it's got to be on a basis that it's accretive for shareholders, or we can see long-term value in terms of the portfolio, or it's deeply strategic and links into a long-term value.

And frankly, some of the valuations we've seen are off-market, which is why, to come back to that disposal question, a lot of our disposals have been coming from the downstream and the midstream, not the upstream.

If you recall, we sold off the best part of $55 billion, if you exclude Russia, at around $100, $110 a barrel way back in the period 2011 to 2014.

So we haven't got that much left in the inventory in terms of disposals.

A lot of what we're doing now is really more in the midstream space and downstream space.

But no, if the opportunities arise we'll certainly look for those.

And then in terms of how would you characterize BP, I think a lot more nimble than we were back in 2010, 2009.

A very focused portfolio.

We've had the change of 2010 to 2014 to completely rebuild the portfolio, which is what we did.

It was specific choices to get out of certain things and specific choices and decisions to go into certain bits of portfolio.

But if you look at the benefits that you're seeing coming through over the last couple of years, I think the characteristic would be of an integrated oil and gas company, focused on providing energy.

And we'll continue to make sure that we build on the two things that we think are distinctive for us, which is around relationships and technology.

And you'll continue to see us do things where we believe the relationships that we develop are unique, certainly in a number of places and Russia would be one of those.

Or where we can bring technology to bear a differentiator from other people.

And I think if we continue to focus on those two things, opportunities will come off the back of it.

Great, thank you very much.

Thanks, Thomas.

We have a question from the web now, from Jags Walia of APG.

And he is asking given the deflation you have seen, is it time to step up FIDs?

Yes, thank you.

Well, so we've done three FIDs already this year.

We had Atoll phase 1, which is an early production scheme that we accelerated.

There was the Tangguh expansion and Trinidad onshore compression.

And we've got two further ones, which I just alluded to, that we're looking at here in the fourth quarter.

I think it's natural, given where we've just come from, if you think, as I just said in the previous question, we rebuilt the Company over 2011 to 2014.

The period 2015 and 2016 was really about restoring balance and getting things back into balance as a primacy in terms of supporting the dividend and that was one of our -- the prima facie priorities that we had.

As we now look going forward, we're now starting to work our way through some of that back inventory of projects and I think you'll start to see more FIDs come through next year.

And of course, we've also got the big series of new projects that come on stream next year that generate significant cash flow growth into the future.

So I think you'll start to see the FIDs start to ramp up next year, with potentially five being completed this year.

Thanks, Brian.

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

Yes, good morning, I've got two, if I may.

In the past, BP has said that the headcount in the upstream was on a trajectory of falling from about 30,000 to 18,000 and I was wondering if you could quantify broadly where we are.

Are we already approaching that 18,000, or are we still some way off?

And secondly, I wanted to pick you up on this comment about high availability of your upstream assets.

I think you mentioned a figure of 95% availability and I was wondering how that compares to 2015 and 2014, and specifically if there was any way of quantifying how much incremental oil you've been able to produce purely by high availability, high utilization of assets that you already have.

Essentially, extra oil production without any CapEx, is there a figure for that?

Okay, Martijn, so on reliability, I don't have the numbers to hand, but I recall back in 2014, I'm guessing for the portfolio, it was somewhere north of 85%, but south of 90%, just from memory, as I recall.

If I think about some of the things that Lamar and Bernard at the time were focused on in terms of reliability, it was one of the key metrics we were looking at and particularly in places like the North Sea.

So I think they've made huge progress in terms of where we've got to so far in terms of the third quarter.

So that was a great example of that, but I think it was running relatively round 85% to 90%, from memory.

In terms of headcount, well you'll see when we actually produce the headcount numbers in the annual report and accounts for next year.

But the last I looked at we were -- if you exclude contractors, and I think that was -- was your question excluding contractors or including, sorry, Martijn?

Well, I remember Mr. Dudley saying at some point from 30,000 to 18,000 and frankly, I'm not quite sure whether at that point he was talking about excluding contractors or including contractors.

I think it's including contractors.

Well if you include contractors, that will be the 30,000 figure, and that is certainly tracking at the end of Q3, we're down to the low 20,000s.

And in terms of our own workforce, we're down at nearly 18,000 at the end of the third quarter.

So quite significant progress already and that's why you're seeing some of those cost benefits come through.

Of course there's the RatEx payments associated with our own employees over that piece, so that will take some time to work its way through the system into next year.

Okay, that's very useful, thanks.

Thanks, Martijn.

Now a question from Iain Reid at Macquarie.

Hi, guys.

Brian, just a couple of questions.

On Brazil, I see you've taken a write-down of the Devon acreage, I presume this is just the exploration part of it.

I'm just wondering what your appetite for Brazil activity is.

We've got a license round coming up next year which has got some off-block extensions of existing fields.

I'm just interested in your appetite for that.

And secondly, on the rig cancellation number, can you just tell us what that was?

And how are you in terms of your rig fleet at the moment?

Is there more of this coming, or are you happy with the quantum of rigs you've actually got under contract right now?

Okay, on Brazil, yes, you're right; it was around the Devon acquisition.

It was the South Campos, it was one of the specific blocks where we had a non-commercial option discovery going forward.

So that's effectively what that write-off is about.

And actually we've written off other assets associated with that acquisition as well.

So I think it's fair to say we haven't yet unlocked the value that we were anticipating, or certainly around the original investment we did into Devon for that piece, although there were other things that came with the Devon acquisition in other regions, like Gulf of Mexico, where we've seen better progress.

So no, we haven't seen anything come out of that really yet, out of that Devon, although we still have a couple of commercial prospects associated with that acquisition that we're still sizing up.

In terms of next license round, it would have to stack up commercially against everything else that we're looking at.

So we're still in Brazil.

I think if the options are sufficiently attractive compared to our alternatives, then they'll rank in that space.

But no, Brazil, we're still there, we're still on the ground and it really would be a question of where commercially the options stack up versus everything else.

And then sorry, Iain, your second question was around?

Yes, the rig cancellation, exactly how much was that in the quarter?

And what about your fleet going forward?

Yes, so for the quarter it was $90 million higher than the previous quarter, so the delta between the two and the actual cost was north of $150 million for the quarter.

We've worked our way through now the whole fleet.

I think in total we had four rigs we've cancelled so far, with a small number we've put on standby.

But again it's really as the team work their way through the inventory of activity we have going forward, we'll continue to optimize.

So I can't say at this point that we're finished with rig cancellations, but as activity ramps up next year it's really around that team that optimizes the rig fleet globally will determine whether commercially the right thing to do is run with the rig, or in this case we chose not to.

And that was the right commercial economic decision to take and we will continue to do that on a point forward basis.

Okay, thanks a lot.

Thanks, Iain.

Next question from Lucas Herrmann at Deutsche Bank.

Yes, thanks very much, Brian, morning.

Just a couple, or two or three, if I may.

Brian, just getting back to the question Anish asked you around annualizing quarters and you sensibly said you wouldn't, but you also said especially this quarter.

I wondered why especially this quarter, what are the things that we're perhaps not seeing in cash that you can see?

Secondly, sorry, just going back to Macondo and the cost this year, can you just remind us whether -- I know you have provided schedules, but the schedules detail annual payments and we're stuck with quarterly reporting.

I just wondered whether the $1 billion or so that was supposed to go out to the States and the short $600 million that was going out to wildlife and others has actually flowed already, or whether that's due to flow the rest of the year.

So really it's, I guess, a break between how much of the outflow is BEL and how much of the outflow is other.

And finally, post-Aker BP, how much operating income did you forego in Norway effectively this quarter relative to last?

Well that last question will definitely test my skill base and memory, so I may well have to come back to you on the last one.

Norway would have been a sub-segment even deeper below where I would look; I'd have caught it through the whole North Sea, but we may have to come back to you on that one, Lucas.

No worries.

On -- let me take the Deepwater Horizon payment schedule.

We will come back to you.

Actually we'll probably put a schedule up on the website, will be easier for everyone to see what the actual -- to the degree that things are settled and we know when the payments are going out, like the state claims, like the civil penalties, like the criminal penalties, all of those things are locked in, and with dates of when those cash payments go.

So we'll come back to you with that.

There were significant payments went out in the second and third quarter, around a raft of settlements, around a big chunk of private claims that we took out outside of the settlement.

And they were taken care of through the court and through a civic process that we had.

And then other costs, like for example, MDL 2185 that we don't talk a lot about, but we also settled that in the second quarter, with a payment of that going out -- due this year.

So we'll come back to you with that, if that's okay, Lucas, in terms of specific payments.

Sure.

And then in terms of annualized quarters, no, the only reason why I said this quarter is that if you took $4.8 billion you could back out the working capital, or you may well find that's sustainable going forward.

You sort of know that the answer needs to be somewhere around $22 billion, so four times four doesn't work for you, so I'll use this quarter.

But if you were going to do a strip of four times, you need one with $5.5 billion in it.

And sorry, just clarity on guidance on cash flow.

You don't include working capital moves in your assumptions on operating cash and coverage of CapEx and dividends going forwards, do you?

No, unless it's sustainable.

Yes, there is a program in both, especially -- a program that was ramped up actually over the last eight quarters to get sustainable working capital out the system.

One of the biggest areas we have where we have flow movements is around our trading barrels that we use, which logically you could say were actually -- is cash and inventory, because you could liquidate those at any point in time.

But that's not something we've gone to at this point, but it's one of the things that we'll be looking at going forward.

But no, only to the degree that it's sustainable, we'd then build that into our cash flow projections.

So for example, if you sell out a refining system, that working capital's gone forever.

Yes.

Brian, thanks very much.

Okay, thank you.

Turning now to Biraj Borkhataria of RBC.

Hi, thanks for taking my questions.

I had a couple on the US onshore business.

The CapEx in that business seems to be quite volatile from quarter to quarter and this quarter was particularly low.

I was wondering if you could give a bit more color around what is driving that and also what is a sustaining CapEx number for that number, to hold production flat over the next year or two on an annual basis.

And following on from that, can you talk about any service pricing pressure you're seeing in the US onshore business?

Whether or not you're seeing it.

Thanks.

Well I'll be seeing Dave Lawler later this week, so I'll find out more then about what he's seeing.

I don't have that to hand here in terms of what we're seeing in terms of services costs.

There is some ramp up in the rigs, particularly for the industry around the Permian, as the prices have come back up around some of the horizontals.

You are seeing some rig activity come up, but I'm not sure that we're seeing anything on the service side, other than what we've already been driven through.

On CapEx, it's down 63% year-on-year, which is completely driven by the planned investment schedule that they have, that the team had.

So they went through a period where they did a series of experiments around particular types of activity, around multilaterals, that they ran.

That's taught them a lot about some of the reservoirs and in actual fact they're going to start re-ramping up and restarting investment in the third quarter.

So you'll start to see some of that CapEx ramp up.

In terms of a point forward capital for that business, we'd really have to come back to you with a figure around that, but I would think something around $0.5 billion or north of $0.5 billion is what you'd expect going forward.

I think when we first put the frame in place, we had up to $1 billion of capital allocated, but again it's really a function of what are the options for us.

That's a great short-term option, if we had to ramp activity up quickly let's say because of prices or because we have discretionary capital, that would be an obvious place where you'd start to do it.

So it can take some of the float in terms of options for us, depending on what's happening in the short term.

It's a great way in terms of getting short-term paybacks and high returns.

And the more and more we learn about that business and the way in which it's run, I think the more value we're going to bring.

So if I could just follow up on Macondo as well, just to clarify some of the earlier questions.

If I add up all the moving parts for 2018, I'm getting to a figure of about $2 billion cash outflow.

I know this will probably be on your website later, I was wondering if that is a sensible number to assume for 2018.

That is pretty much spot on with what I have in the forward plans.

Notwithstanding any other assumptions we have around where we are, around any de minimis type claims that might be out there.

But in terms of materiality, something around $2 billion is a good number.

And actually just since this question keeps coming up, it's going to be -- for this year the total cash out payments will be anywhere from $6 billion to $7 billion, for 2017 anywhere from $3.5 billion to $4.5 billion and there are ranges around these.

And then once you get into 2018, it goes into $2 billion and then 2019 onwards it's $1 billion to $1.3 billion, dropping down to $1 billion at the end of the piece.

Thanks, that's really helpful.

We will get a schedule out there for you though.

All those settlements feel like an awful long time ago now, but we will get those schedules on the website so you can see them.

Great, thanks.

Thanks, Biraj.

A question now from Alastair Syme of Citi.

Thanks very much, Jess.

You've got on the notes that you've lowered some of your long-term oil and gas price assumptions, as you've redone your reviews this year and I think also the discount rate.

So can you talk a wee bit about what's going on and also the drivers of the impairment reversals?

And then secondly, you've mentioned a couple of times the Mad Dog 2 FID.

What exactly are you seeing in terms of accelerating or deepening -- or deflation in the offshore?

Thank you.

Well, Mad Dog phase 2 is imminent, I guess.

We're right in the fourth quarter now, we're ready to FID.

I think our partners would like to see that in the first quarter of next year, so maybe it's slightly out of sync.

I think the project is pretty much there now.

It's significantly below even -- it's certainly below the $10 billion that we talked about and now it's drifting to a number significantly below that as well.

So I think that's ready to go and now the key is it gets delivered at the new cost set that we have and certainly that's the mantra that Bernard and the team have got right now in terms of where that's got to.

On price assumptions, yes, we've just done -- and you'll have seen from the energy outlook that we put out there, our new set of long-term price assumptions have effectively moved to $75 real for oil in the long term.

And in terms of impairments, we take the current price today and then smooth it up to that level out at 2022.

And gas we moved out to $4 real in terms of those impairment tests.

We also looked at the whole range of all of our discount factors and other metrics that we reviewed, as we do annually in this quarter, and that's reduced the discount rate down by a factor.

And then along with running that, that then created a trigger for all of our consolidated units in the upstream.

And that's where you've seen these impairment write backs coming back this quarter, but that's just purely a function of running those models.

Brian, any particular reason why Angola and North Sea would feature more predominantly in those impairment reversals?

No, not specifically, other than the size of the assets, what the reserves positions look like.

But it really is a function of once you've had the trigger to go and look at them -- and we've looked at them a number of times over the last couple of years, we've had a couple of triggers on Angola and North Sea before.

If you now run the new set of price assumptions, that's where those carrying values come out.

It's a pretty rigorous process, it's very transparent, we run it every year and it's led to those write backs this quarter.

Great, thank you.

I should also say there's a lot of moving parts in that number and since we went through all of the consolidated units, there were some positives and negatives right across the piece.

The net position is what you saw.

Great, thank, Brian.

Okay, we'll take the last question from Chris Copeland of Bank of America.

Thank you, Jess.

Brian, just two quick ones.

Of your exploration expense which came in for the quarter around $800 million, can you just confirm how much of that is in your non-operating income and how much is actually flowing through your reported underlying upstream?

I think you've specified the Brazilian write-off, but just wanted to see the total number.

And any comment you want to give us on a run rate as far as underlying exploration expenses are concerned.

And lastly, wanted to check how you're feeling about your Indian options in terms of future FIDs.

Not necessarily in the next six months, but any latest developments that you can report from there.

Thank you.

So I assume you're talking exploration write-offs when you say exploration expenses.

Yes, correct.

The biggest thing that you saw coming through in that quarter was actually the delta off the Brazilian asset that we talked about earlier, then lots of small pieces.

But we're getting to a stable, steady state number going forward.

But you had a figure -- you mentioned $800 million.

Yes, that's for the third quarter, what you call exploration expense, of which there are 687 exploration expenditure write-offs.

But I wondered whether you had to hand a breakdown of how much of that has gone through your non-operating--

Oh, I'm sorry.

--and how much is reflected in underlying--

Yes, there's about -- there's also -- so we need to come back on the specifics, but there's over $300 million of NOIs hitting that number as well, which also relates back to the Devon acquisition.

So it's about -- from memory, it's somewhere around $330 million, $340 million of that is NOI.

Right, so if I take that off the $800 million mark, then we're still left with more than $500 million reflected in your underlying upstream earnings.

Correct, that's correct.

Thank you, yes, good.

Sorry and then in terms of India, well we still have current production under the existing formula, which today creates around $2.50 mmBtu.

We now have the new gas pricing policy that we've come up with a price north of $6, I think it was $6.50 last time I looked.

And we're working with our partners to progress what those development options look like.

I think we see good opportunities aligned with what the Government of India wants in terms of its desire to bring on its own domestic gas.

So I think there are some great opportunities for us.

And we still have the issue around arbitration, which will resolve itself as that progresses through the legal process going forward.

Okay, so should we have that on our list for 2017 FIDs?

It is a possible FID that we'll look at for next year, but again it'll have to rank against all the other options that we have.

Sure, okay.

Thanks, Brian.

All right, everybody, well thank you very much.

I know it's a very busy day for you today, so we appreciate you dialing in.

Brian, would you like to say anything in conclusion?

No, thanks, Jess.

So well, first of all, appreciate you've quite a busy day today because there are lots of results to try and collate and hopefully coming out early this morning has helped somewhat with that process.

I think it comes back to where we are in the process.

We are now well into the rebalancing of the Company.

We have a big series of new projects coming on stream next year.

I think we can now see the balance point sometime into next year, I think we see some firming in prices from where we are now, but nothing majorly north of where we see around $50, $55 a barrel.

And nothing changes within the Company in terms of continuing to focus on safe and reliable operations.

That's what underpins everything that we do.

And thank you very much for taking the time this morning.