英國石油 (BP) 2015 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 2015 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 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 Bob.

Thanks, Jess, and hello, everyone.

Thanks for joining us.

It has been a very important quarter for BP.

We reached agreements in principle in the United States to resolve the largest remaining liabilities in relation to the Deepwater Horizon oil spill.

This has been recognized as a landmark step forward by all parties and leaves us all able to chart a much clearer course for the future.

The second quarter environment has also continued to test us.

As you've seen, our upstream earnings for the second quarter remained under pressure, reflecting continued oil price weakness and the large maintenance program we have underway this summer.

The result also includes some large non-cash write-offs.

At the same time, there is clear evidence of the underlying strength and resilience of our businesses.

Our downstream continues to perform strongly, and there are clear signs of efficiencies, sustainable efficiencies and cost reductions right across the Group.

Underlying cash flow for the quarter also improved.

So I will start with an overview, including our thoughts on the future.

In a moment, Brian will go through the results in detail.

Then I want to come back and give you an update on our interests in Russia and take a brief look at progress in our businesses.

After summarizing, there will be time for Q&A.

I'd like to start with a reminder of the near-term priorities we laid out in February.

As you know, we have held the view for some time that oil prices will be lower for longer, but whatever the oil price charts look like, we are clear on what we need to do.

To describe this simply, we focus on the four Ds of delivery, divestments, discipline and the dividend.

On delivery, we've had a strong first half of the year; Group safety performance has improved across a number of metrics compared with 2014.

In the upstream, we have started up two new projects this quarter, both in Angola, while making strong progress on the milestones that support our next wave of startups.

We've also completed six turnarounds as part of our major program for the year.

And in the downstream, as you've seen, the business continues to perform strongly.

We are seeing continued safe, reliable and efficient execution right across the Group, downstream and upstream, which is maintaining operational momentum at the same time as we reset for the new environment.

Turning to our divestments, we continue to strike agreements toward our $10 billion program, with $7.4 billion agreed to date.

The total since 2010 is now roughly $45 billion, not including the TNK-BP divestment of $26 billion.

On discipline, our work to reset capital and cash costs is now moving fast and I will show you in a moment.

This all works towards our focus on rebalancing our financial framework to manage through a period of low oil prices, while sustaining our dividend as the first priority within that framework.

We are confident these remain the right priorities for the near term.

Now turning to our ongoing work to reset capital and costs across the Group.

We now expect our organic capital expenditure to be below $20 billion for 2015, compared to our guidance back in a $100 world of $24 billion to $26 billion.

This is being achieved for this year largely through re-phasing and paring back of marginal activity.

But we were also seeing benefits from deflation.

Industry commentary suggests offshore costs are reducing rapidly and this is consistent with what we are seeing in our supply chain.

This gives us confidence in sustaining a lower level of capital spend over the medium term, while maintaining the same growth aspirations.

We are also starting to see results from the many programs we have in place to reset our controllable cash cost base.

We are realizing benefits from the investments we've made over the past few years in approving reliability and the simplification that followed the reshaping of our portfolio.

As well, our intensified efforts to reset costs in response to the environment is gaining momentum.

Total Group cash costs year to date are around $1.7 billion lower than the same period last year.

This is despite the inclusion of around $400 million of rig cancellation costs taken as an operating item.

This is an encouraging early indicator of progress, especially given there is usually a lag before our cost reductions fully reflect in results.

What we are seeing is an organization that is adapting rapidly to a new environment by adopting a more cost conscious business model, and we will continue to identify more opportunities for simplification and efficiency.

Non-operating restructuring charges are currently expected to be closer to $1.5 billion by the end of 2015, relative to the $1 billion we announced back in December, and reflects the faster pace.

So we are in action on all fronts related to cost.

We are optimizing the scope of our activities, leveraging deflation in the supply chain, and changing how we manage our own internal cost, including extensive simplification of our organizational structures in every part of the business.

We have, by necessity, become too complicated.

We believe the benefits from the changes we are making are largely structural, and will be sustainable over the long term.

Let me turn now to a brief look at the longer term.

Back in February, we said that we anticipated a reset phase lasting around two years, during which our aim is to rebalance the Group's sources and uses of cash to underpin our dividend.

Our work on costs is a strong focus right now, but we are mindful to achieve this without compromising our longer-term goals.

This involves testing and getting even clearer on the fundamental drivers of our business model in the new environment.

We are taking the time and, importantly, the opportunity to understand what deflation can deliver, and how our portfolio might respond in a range of price scenarios.

What I can tell you now is that we have some strongly held principles that will not change.

Our focus on value over volume will remain.

It is central to our strategy, and a guiding principle in any price environment.

In practice, it means we constantly look to create value by optimizing and high grading our portfolio, whether through divestments, farming out early life assets, selective acquisition, or simply finding smarter ways to work our portfolio harder, as with the US Lower 48.

Our commitment to capital discipline is also unchanged.

As already noted in the upstream, we expect to see an impact from deflation, resulting in a structurally lower level of capital spend for a given level of activity over time.

Our aim remains to define a disciplined level of capital spend to grow our portfolio in terms of both operating cash flow and production.

To be clear, our strategy still aims to grow production, while seeing growth in operating cash flow as a better measure of value.

It has become a lot harder to plan activity in the current environment, but we remain focused on three areas.

First, it's about sustaining activity in our pipeline of core projects, ensuring every dollar of capital's optimally invested, and leverages any deflationary opportunity.

We believe that the strong pipeline of projects and appraisal options we showed you at our Upstream Day in December, extending well beyond 2020, are of sufficient quantity and quality to be a key driver of growth.

As a reminder, over half of our production from new major projects to 2020 is already under construction, and these projects remain on track.

Second, we see management of our base oil and gas production as a significant lever.

We continue to make excellent progress.

Our producing assets are becoming safer and more reliable; we are improving operating efficiency, and working to maximize recovery from our reservoirs.

This is enabling us to maintain historical levels of decline, within the boundaries of a lower capital budget.

And third, we are constantly looking for new, high value options to add to our portfolio near term.

This can come, for example, through inorganic deepening in strategic areas, or through a shift in exploration to more near field, high value prospects, allowing faster pull-through.

In the downstream, we expect continued strong performance from a combination of our advantaged assets and our growth and efficiency programs.

Group-wide, we believe that our balanced high quality portfolio, and our ongoing focus on capital and cost discipline, gives us a strong platform from which to define a model to grow shareholder value.

This all works towards a final fundamental principle, that of returning value to shareholders through distributions over the longer term.

We will, of course, share more detail with you as the environment firms, and our plans take stronger shape.

The key point for today is that we have made a head start on resetting our capital and cost, and believe we are well positioned for the challenges ahead.

I'll now hand over to Brian to take you through the quarter.

Thanks, Bob, and hello, everyone.

Starting with the environment: Brent oil averaged $62 per barrel in the second quarter, up from $54 per barrel in the first quarter, but still significantly below the average of $110 per barrel in the same period last year.

Oil prices have fallen back again over the last few weeks, in response to persistent weakness in market fundamentals.

Although demand has been stronger, OPEC production is running higher than at 2014 average, and production in the United States has remained resilient.

The recent agreement to lift certain Iranian sanctions has also raised the prospect of additional production coming on to the market.

Henry Hub gas prices averaged $2.65 per 1 million British thermal units in the second quarter, over 40% lower than the same period in 2014, and slightly lower than the first quarter average.

Continued strong growth in gas production has left the market oversupplied, pushing gas prices down to levels that compete with coal for power generation.

Our global refining marker margin averaged $19.40 per barrel in the second quarter, the highest level since the third quarter of 2012.

Margins have been supported by strong gasoline demand, tight supplies on the US West Coast, and low product stocks outside of the United States.

At the same time, US/Canadian crude differentials were at their narrowest since the second quarter of 2009.

We expect oil prices to remain soft over the short to medium term, while we expect refining margins to respond to changes in regional supply and demand, as we see out the summer driving season in the United States.

So turning to the results: BP's second quarter underlying replacement cost profit was $1.3 billion, down 64% on the same period a year ago, and 49% lower than the first quarter of 2015.

Compared to a year ago, the result reflects significantly lower upstream realizations, higher exploration write-offs, including additional one-off charges associated with Libya, and the reduced contribution from Rosneft, partly offset by a strong downstream performance, and lower cash costs across the Group.

Second quarter operating cash flow was $6.3 billion.

And we've taken a further $270 million non-operating restructuring charge in today's results, bringing the cumulative charge to $920 million, against the near $1.5 billion charge we now expect to see before the yearend.

The second quarter dividend, payable in the third quarter, has been announced as $0.10 per ordinary share.

Turning to highlights at a segment level.

In upstream, the underlying second quarter replacement cost profit, before interest and tax, of $490 million, compares with $4.7 billion a year ago, and $600 million in the first quarter of 2015.

Notably, upstream earnings were impacted by around $600 million in Libya, including exploration write-offs and other costs, primarily due to circumstances in the country.

Compared to the second quarter last year, the result reflects significantly lower liquids and gas realizations, and higher exploration write-offs, partly offset by lower cash costs, including the benefits from simplification and efficiency programs.

Excluding Russia, second quarter reported production versus a year ago was 0.3% higher.

After adjusting for entitlement and portfolio impacts, underlying production decreased by 1.7%, mainly due to increased turnaround activity, partly offset by the ramp up of major projects which started up in 2014.

Compared to the first quarter, the result reflects exploration write-offs of $800 million, relative to a charge of less than $100 million in the first quarter, and the impact of our seasonal turnaround program, largely offset by higher liquid realizations and the absence of cancellation charges relating to two deepwater rigs.

Looking ahead, we expect third quarter reported productions to be broadly flat, compared to the second quarter, primarily reflecting levels of maintenance activity comparable for the second quarter.

In the downstream, the second quarter underlying replacement cost profit, before interest and tax, was $1.9 billion, compared with $730 million in the second quarter last year, and $2.2 billion in the first quarter.

This result contributes to strong first half earnings delivery for downstream.

The fuels business reported an underlying replacement cost profit, before interest and tax, of $1.4 billion, compared with $520 million dollars in the same quarter, and $1.8 billion in the first quarter of 2015.

Compared to a year ago, this reflects an improved refining environment and production mix, partially offset by weaker North American crude differentials, a higher oil supply and trading contribution, returning to average levels for the quarter, and cost benefits from simplification and efficiency programs.

Compared to the first quarter, the result reflects a lower oil supply and trading contribution, relative to a strong first quarter, and higher seasonal turnarounds, partially offset by improved refining margins and fuels marketing volume growth.

The lubricants business delivered an underlying replacement cost profit of $400 million in the second quarter, compared with $310 million in the same quarter last year, and $350 million in the first quarter of 2015.

This strong quarterly performance reflects continued momentum in growth markets, premium brand performance and benefits from our simplification and efficiency programs, leading to lower costs.

These benefits were partially offset by adverse foreign exchange effects.

The petrochemicals business reported an underlying replacement cost profit of $80 million in the second quarter.

Looking forward to the third quarter, we expect reduced refining margins and lower levels of turnaround activity.

Turning to Rosneft: based on preliminary information, we have recognized $510 million as our estimate of BP share or Rosneft's underlying net income for the second quarter, compared to around $1 billion a year ago, and $180 million in the first quarter.

Our estimate of BP's share of Rosneft's production for the first quarter is just over 1 million barrels of oil equivalent per day; an increase of 1.8%, compared with a year ago, and 1% lower than the previous quarter.

Further details will be made available by Rosneft with their results.

Earlier in July, we received our share of the Rosneft dividend in respect of 2014, which amounted to $271 million after tax.

In other business and corporate, and we reported a pretax underlying replacement cost charge of $400 million for the second quarter, in line with guidance.

The underlying effective tax rate for the second quarter, was 35%.

Excluding the one-off North Sea deferred tax benefit reported in the first quarter, we continue to expect the full year, effective tax rate to be lower than the full year 2014 figure of 36%.

Turning to Gulf of Mexico, oil spill costs and provisions.

As we described on July 2, BP exploration and production reached agreement, in principle, with the United States Government, and five Gulf Coast states, to settle all federal and state claims arising from the Deepwater Horizon oil spill.

The agreement with the states also provides for the settlement of claims made by over 400 local government entities.

The settlement provides for total payments of up to $18.7 billion, over a period of 18 years.

These agreements are subject to finalizing definitive agreements, which will include a consent decree with the federal and state governments, all of which will be subject to final court approval.

Yesterday, we signed releases from the vast majority of local government entities, and we'll be making the payments required within the next few weeks.

Turning to other Gulf of Mexico legal matters, the settlements do not include claims relating to 2012 Class Action settlement, with the plaintiff steering committee, including business economic loss claims not provisioned for.

Private claims not included within the Class Action settlement or Private Securities Litigation in MDL 2185.

The charge taken for the incidents for the second quarter was $10.8 billion, which takes the total cumulative pretax charge to $54.6 billion.

This reflects around $10 billion associated with the government settlements just mentioned, around $460 million related to business economic loss claims not provided for, adjustments to other provisions, and the ongoing costs of the Gulf Coast restoration organization.

It is still not possible to reliably estimate the remaining liability for business economic loss claims and we continue to review this each quarter.

The pretax cash outflow on costs related to the oil spill for the second quarter was $110 million.

This slide compares our sources and uses of cash in the first half of 2015 to the same period a year ago.

Operating cash flow in the first half was $8.1 billion, of which $6.3 billion was generated in the second quarter.

This compares with $16.1 billion in the first half of 2014, and $7.9 billion in the second quarter of 2014.

Excluding oil spill related outgoings, first half underlying cash flow was $8.9 billion.

This reflects the impact of lower oil prices on earnings, as well as a build of $1.4 billion in working capital in the first half of 2015, which we expect to unwind as the year progresses.

Our organic capital expenditure was $8.9 billion in the first half, and $4.5 billion in the second quarter.

We received divestment proceeds of $2.3 billion in the first half of 2015, including $530 million in the second quarter.

Now turning to the financial framework, and the approach we laid out to you in February.

We now expect organic capital expenditure to be below $20 billion in 2015, and have agreed $7.4 billion of our $10 billion divestment program.

We are taking advantage of sector deflation to optimize our capital costs, while actively resetting our cash costs to deliver sustainable efficiency.

These changes are largely structural, and they support our principal objective of rebalancing sources and uses of cash, so that underlying operating cash flow covers capital expenditure and dividends.

We are working to reestablish this balance for a sustained weaker environment.

And lastly, just a few words on gearing.

Our policy, since the Deepwater Horizon incident, has been to maintain gearing within a band of 10% to 20% while uncertainties remain.

At the end of last year, our balance sheet reflected gearing at 16.7%, well within this band, against the backdrop of the near $100 per barrel average oil price environment in 2014.

Gearing at the second quarter stands at 18.8%.

This reflects average oil prices of $58 per barrel over the first half of this year, and an impact of around 1%, due to our recent agreements, in principal, to settle with the United States Government, and Gulf states.

Once these agreements are finalized, a considerable uncertainty in relation to our financial framework will be removed, placing our gearing band in a much stronger context.

Now let me hand you back to Bob.

Thanks, Brian.

First, to recent developments in Russia.

In June, Rosneft held their annual general meeting in St.

Petersburg.

Amongst other matters, shareholders approved the once a year dividend, payable for 2014, as Brian mentioned, and voted for the new Rosneft Board.

In addition to my own reelection, we now have a second BP executive on the nine person Board, Guillermo Quintero.

Guillermo is currently BP's regional president in Brazil, and is a highly experienced oil and gas Executive.

Beyond our shareholding in Rosneft, we recently signed agreements to purchase a 20% equity share in Rosneft's Taas project.

This project is an existing conventional oil field in Eastern Siberia which currently produces around 20,000 of oil per day.

The full field development plan for Taas ramps up production to 100,000 barrels a day by the end of the decade, with further potential for gas production.

Along with the Taas equity, we also agreed three conventional exploration areas of mutual interest with Rosneft: one in Eastern Siberia, located around the Taas interest, in a relatively unexplored region, and two in the already prolific Western Siberian hydrocarbon basin.

We are pleased with the progress, both through our shareholding and also in partnership with Rosneft.

As always, we remain mindful of the geopolitical situation, but look forward to continuing to pursue these and other potential future opportunities where not prohibited by sanctions.

Turning to the upstream, and starting with exploration, we made a high value discovery with the Atoll well, offshore Egypt, in the first quarter.

In the second quarter, we've had a further gas discovery at the Nooros prospect in the Abu Madi West lease.

We expect production from this well later this year and we see follow-on opportunities in neighboring BP operated blocks.

In projects, we successfully started up Greater Plutonio Phase III in June, our second major project startup in Angola this year.

Two further startups are planned for 2015: the In Sala southern fields project in Algeria, and the Western Flank A project on the Australian North West shelf.

We continue to make progress on a number of projects set to start up over the next few years, including in Oman and Shah Deniz 2 projects, among others.

In our operations, we remain focused on the optimization of our base assets.

We have completed six turnarounds this year, with three currently underway and a further six yet to start.

We are seeing the results of investment in our producing assets, with BP operated plant reliability up from around 85% in 2011, to 94% in the first half of 2015.

Our asset-specific plans in the UK North Sea have helped to improve BP operated plant reliability from 67% to 82% over the last six quarters.

And in our drilling activities, we have decreased non-productive time by over 20% since 2012.

All of these efforts have allowed us to increase operating efficiency and support underlying production growth, while maintaining strict capital discipline.

As I highlighted earlier, we are resetting our cost base and capital frame and driving deflation efficiency into the way we work across the upstream.

Since the beginning of the year, we have been working with our suppliers to rebase our cost in some of our biggest areas of upstream spending.

And you can see a range of rate reductions we've achieved to date on the chart.

We expect the benefits to show up in both capital expenditure and cash cost.

Examples include a 33% savings against the subsea installation budget on one of our Gulf of Mexico expansion projects.

Another is negotiating a rate reduction of over 30% for drilling our latest development well on the Mungo asset in the UK North Sea.

And around 10% rate reduction from major well service suppliers globally, including a 20% rate reduction on tubulars.

We've also delivered additional efficiencies through optimizing activities and processes.

For example, an 18% reduction in logistics costs through more efficient use of boats and helicopters in our operated Gulf of Mexico assets; a savings of 19% from optimization of our repair and maintenance program in Angola; and an 8% savings on well placement costs through improved monitoring utilization of components in Trinidad.

At the same time, we are right-sizing our organization to reduce costs further.

Since 2013, upstream staff headcount is down 8%, while agency headcount is down 37%.

Expatriate employee numbers are at their lowest level since 2011.

And, as we have said before, we are exercising strict capital discipline across the upstream.

We are testing the resilience of project economics in a low price environment and progressing only the highest quality options in the portfolio.

We are retaining optionality on remaining resources and recycling projects, where we see potential for optimization.

On our Mad Dog 2 project in the Gulf of Mexico, standardization, scope optimization and industry deflation is enabling us to develop around 90% of the resources using half the capital, whilst retaining optionality for future expansion.

Our global project team are now driving this agenda systematically across all of our projects worldwide.

In the Lower 48 of the US, we have empowered our new business units to implement their own capital and operating efficiency improvements.

We are beginning to see the benefits of these efforts.

Operating costs are trending lower, and in our Woodford and Haynesville assets we have halved the costs of bringing new wells on stream.

In the downstream, our strong first half performance demonstrates clear progress against the strategic goals we outlined in February this year.

In fuels, our focus on advantage manufacturing and marketing growth is beginning to deliver additional gross margin benefits, with year-on-year pretax earnings growth of $2 billion in the first half.

We continued to upgrade our portfolio during the quarter and we ceased refining operations at our Bulwer Island refining facility in Australia.

In addition, we recently announced, together with our partner Rosneft, a planned reorganization of our German refining joint operation, which will further simplify our fuels organization and operations.

Our fuels marketing business is also experiencing growth, with volumes up by around 2% year to date.

In lubricants, our sustained focus on growth markets and premium products has contributed to strong first half pretax operating profits, over 15% higher than 2014.

And in petrochemicals, our new world-scale PTA plant in Zhuhai, China, is now fully commissioned and operational.

This plant, with its advanced technology is expected to operate with industry leading operating cost efficiency, creating a higher earnings potential business, more resilient to bottom of cycle conditions.

Across the downstream, we are also seeing significant year-on-year benefits from our simplification and efficiency programs.

Cash costs were 15% lower at the half-year than the same period in 2014.

This year-to-date reduction includes the benefits from a comprehensive simplification in efficiency program, comprising some 30 initiatives that are currently underway.

In addition to the announced proposal to restructure the German refining joint operation, we have simplified our fuels organization, reducing the number of businesses from nine to three, and are also simplifying our lubricants business structure.

Together, these changes will eliminate duplication, reduce interfaces and simplify our route to the market.

We're also streamlining our head office functions, eliminating activity which does not directly support our strategy and simplifying the way we operate.

And these changes have reduced the number of downstream head office functions by over 50%.

And in manufacturing, we're delivering efficiencies through the application of technology and implementing plans, refinery by refinery, to further improve our competitiveness.

As well, we are maintaining strict cost discipline in our daily operations, including a focus on third-party costs.

Taken together, these programs underpin the accelerated delivery of the $1.6 billion per annum of downstream efficiencies we highlighted in February.

So let me leave you with just a few thoughts in summary.

It is a challenging time for our industry, but I remain confident that moving quickly, to simplify and reset the Company for a sustained weaker environment, is the right thing to do for all seasons.

I believe we've made a good start.

We are staying very focused on operational delivery; we're working steadily to complete our planned divestments; and we are resetting capital and cash costs in a way that drives sustainable efficiencies.

This supports our efforts to rebalance our sources and uses of cash and ensure we can sustain our dividend.

This is the clear priority within our financial framework right now.

While the amount is very large, we also recognize that we have found a realistic path to closure on the largest remaining legal exposures in the Gulf of Mexico.

Removing this legal overhang and uncertainty allows us to focus on our future.

Looking further out, we see the strength of our portfolio, and our strong commitment to capital and cost discipline, giving us a strong base from which to define the right model to grow shareholder value in a new environment.

And I think on that note, I'd like to thank you for listening and now let's take your questions.

(Operator Instructions).

Jason Gammel, Jefferies.

My question is around the cost efficiencies that have been gained, the $1.7 billion year to date.

You've made reference to having to absorb the rig cancellations within that; I would assume that this is a process that was ramping up from the beginning of the year.

So can you give us any color, Bob and Brian, around how sustainable this is in the back half of the year?

Are there further gains to be made?

Jason, hi, thank you.

There are further gains.

We're well into restructuring of costs in the upstream and we'll continue on later this year.

Most certainly, they will be in some of our big centers around the world, Houston, some more in Aberdeen.

You're right, the rig cancellation cost, had we not done that when use of this capital, we would have even seen a higher cost reduction.

Yes, naturally also to point out that we've taken a higher restructuring charge as well this quarter.

Just to flag that in December we'd said that we'd set aside $1 billion for restructuring; it looks now like more like $1.5 billion for this year.

If you recall, this program started on the corporate side, post the big disposal program.

Around about 2.5 years ago, we started talking to you about the restructuring of our corporate overheads.

That's really what led us down the path of the $1 billion restructuring.

We're now into the deflationary period in terms of deflation coming through now in the results and in the cash costs, so I think you'll see more as the year progresses.

And the additional restructuring charge we've taken this quarter, I think, is a signal that there's more costs to come out the system.

So can I just take it from that that the controllable costs could be down by more than $3.4 billion on an annual basis?

No, I think I've always said on these calls, never, never go for multiples of what you see in the first half of the year.

There's lots of moving parts to the numbers.

The general trajectory, though, is still down.

Okay, great.

Thanks.

Blake Fernandez, Howard Weil.

Brian, I wanted to clarify, you made some comments on the gearing band of 10% to 20% and, obviously, you're at 18.8% at the end of the quarter.

With more clarity on the legal front, I just want to make sure, were you insinuating that that band could retrend higher back to the 20% to 30% level that we've seen in the past?

Thanks, Blake.

I think it's really just putting it in the context of where we are.

We moved the 10% to 20% band post 2010 as we refinanced the balance sheet.

And I think it was just right with the degree of uncertainties, both in terms of Macondo litigation, but also the general environment that we moved into that band.

I think the only point I'm making is that where we now sit in that band is a much stronger context now that we know the scale and scope of the liabilities, pretty much the majority of liabilities associated with Macondo, going forward.

And the way in which that deal has been negotiated over 18 years creates the space to say, actually, within the current context, that's a much stronger place to be.

In terms of where we sit into the future, there are so many moving parts, we're not signaling at this point that we're moving out of that 10% to 20% band.

But it's a far more comfortable place to be, knowing what the liabilities are, going forward.

Okay, thanks.

If I could just ask one follow-up too, maybe of Bob.

Bob, you've had a [thesis] of lower for longer on oil, which has proved correct so far.

You've also come out recently in support of a carbon pricing system and, in looking at the project sanctions, the only project you've really moved forward on is the natural gas project.

I'm just curious if you can elaborate a little bit, if we could potentially have a strategic shift underway here in preference of gas over oil?

Thanks.

Yes, Blake, we have just moved past the 50% -- we're roughly, right now, at 50% of our portfolio in terms of production is now gas versus oil.

Part of that is because we had oil projects coming on and, in the last two years, we have sanctioned significant large gas projects.

So down the road by the end of the decade, we'll be between 55% and 60% gas when the Oman projects and the Shah Deniz projects come on.

Strategic shift, it's clear that carbon pricing and carbon emissions are going to be a focus of the world.

We think having that reduced carbon footprint is going to be a good thing, but we're certainly not abandoning the oil and gas industry, or the oil industry.

Carbon pricing, we have a view on carbon pricing in the sense that the world is coming together in December.

We think that the world really does need a framework to work with, and number one should be energy efficiency, because that is the biggest single lever in terms of reduced emissions.

And after that, a carbon pricing that can be used by the world where the proceeds from that don't just go into the general funds of the world, but actually move to solving the transition to lower carbon energy over many decades.

And we've taken a position on that with, now, 11 other companies in an oil and gas climate initiative.

It's going to be part of the focus.

Strategic shift, I think so.

I think it's a natural one with our portfolio and the projects we see ahead.

I appreciate the color.

Thank you.

Jon Rigby, UBS.

Two questions, actually.

The first, just a point of clarification on these cash cost reductions.

Is the $1.7 billion the savings that you made over the first half of the year, or were you running ratably at the end of the second quarter, just so I can get a handle on that?

Secondly, just picking up on the high exploration charge that you've taken this time around, which a large portion is write-offs.

So I understand that it's not cash, but I can see from your accounts that your intangible drillings costs and stuff that you've got on the balance sheet have been rising very significantly over the last three or four years.

Is the process of looking at your portfolio, rescheduling when you go ahead with projects, deciding whether those projects are appropriate or not, going to have implications for what you're carrying on the balance sheet?

And, therefore, should we be expecting larger, non-cash costs over the balance of this year and maybe into 2016 running through the exploration charge?

Thanks.

Jon, the first question, it's a straight simple delta.

It's not run rate, it's the absolute quantum, is $1.7 billion lower first half versus first half.

On the intangibles, you're right, I think last time I looked, it's tracking just below $20 billion in terms of exploration intangibles and we'll continue, simply, to process each of those prospects.

It's increased over the last four or five years, given the amount of ramp up we've had in the exploration activity, so it's not surprising.

The typical exploration write-offs had been running at an average over the last four or five years around $400 million a quarter.

You've seen more this quarter, and even last year, but I don't think it's an indication of a trend that you should expect more and that continue to ramp up going forward.

It's just a reflection as we look at specific projects.

And Libya was a bit of a one-off this quarter, given where got to with the process and what was happening in the country itself.

So I wouldn't take that as a leading indicator for future.

So a [filtering] process ongoing?

Yes, we're going through all the prospects right now.

It's a good place to be in terms of the prospects that we have, going forward, and some of those we'll choose to progress and some we won't.

Right.

Okay, thank you.

Irene Himona, Soc Gen.

Just two questions, please; firstly on lubes.

In Q2 obviously the profit rose very substantially.

I think we were up 26% year on year, and for a long time the average quarterly run rate was around about $300 million, $320 million.

In Q2, we are close to $400 million.

Given that you don't disclose anything other than profit, is there some guidance you can give us on whether the Q2 lubes profit is sustainable, going forward?

And then my second question concerns dividend payout.

Earlier you said, costs and CapEx, do you look at the payout ratio at all?

Is it part of your financial framework?

Thank you.

Thanks, Irene.

I'll take the lubes and then Brian on the dividend.

I think we are seeing some things that are -- we don't give out the details of lubricants, but a strong factor is the growth of some of our power brand sales and some of our lube brands, like Edge and Magnatec and GTX, especially within the Americas and China.

So I think we are seeing sustainable sales increases and volume increases in those markets, which are growing.

And then on the question around payout ratios, absolutely Irene, of course we look at those.

It's important that we make sure that we can underpin the balancing of sources and uses of cash.

And I think, as Bob laid out in his comments, we could see the oil price getting soft at the middle part of last year, so we'd already laid in plans for this year at lower prices.

Obviously, we saw the big drop-off in the fourth quarter and we've adjusted things accordingly through this year.

And it will take a couple of years, as we get things back into balance in terms of sources and uses of cash.

But yes, we do look at payout ratios.

Thank you.

Guy Baber, Simmons & Co.

Bob, I believe you mentioned that growth through the cycle was still a key objective for the Company, so I was hoping you could just elaborate on that comment, particularly in light of the re-phasing of projects and the significant reduction to capital spending you are achieving relative to the view just 12 months ago.

So the question is, at sub $20 billion of CapEx annually, do you believe that that is enough capital to organically grow the business longer term and replenish the portfolio?

Or will that level of CapEx need to be supplemented by some amount of inorganic activity?

Just hoping for some more thoughts there, and then I had a more specific follow-up as well.

Yes, Guy, we do think that we can see underlying production growth with the projects we have and these levels of capital out through the end of the decade.

I think we can see, with deflation, we can continue to develop these projects and move them forward.

And we'll just get more activity out of less CapEx, going forward, so I think we can.

And the deflation, to give you some extent of the deflation across the various geographies and sectors, the rig rates have come down very quickly with drops of about 30% in some places, and more already seen in some places.

You've got the real impact of oversupplied market there.

Our development cost for new projects we're projecting to deflate by as much as 20% to 30%, depending on the project, so we think there is absolutely scope here for having growth through the cycle with lower capital.

Okay, very helpful.

And then I wanted to discuss also just the US Lower 48 business a bit more.

But you have a half-year under your belt now of that business operating as a separate entity.

The macro environment has also changed tremendously from the time when you announced the separation there.

So I was just hoping, at this juncture, you could give us an update as to how that business has performed, relative to expectations?

The extent to which, perhaps, you've been able to improve the cost structure, and how the performance of that business is influencing strategy and your thoughts around capital allocation as you move into next year?

And also, how do you assess at this point the size of your position in the Lower 48, relative to what you would view as strategically optimal?

Okay, Guy, that sounds like a half hour answer to a question.

It's a good one, though.

There's no question we feel like we've improved the competitiveness of the business.

We've done all kinds of structural things, organized it into five sort of accountability-based business units that can move very quickly in implementing capital changes and cost reductions.

So far, the kinds of things we're doing is we're managing the producing wells better, new artificial lift, we're reducing some of our cost to drill wells.

We've actually increased the number of rigs running from around two up to 10 now across the business units.

At the end of 2014 we only had two, in fact.

We've got seven in the mid-continent area, two rigs in East Texas and one rig in Wyoming.

We've also seen an increase from the drilling and the activity in the percentage of liquids, which is up pushing 20%, about 18% now.

So our production across Lower 48 is about 280,000 barrels per day equivalent.

So we're pleased with it; obviously it's challenged with the lower prices right now, costs coming down.

The executive team has come in to that business.

We have reduced the size of it in terms of the number of people.

I think it's much more efficient, and it's moved out of our Houston campus into lower overhead activity.

So we continue with the desire for it to be a market visible, high return, onshore operator in the US.

It's got about 1,200 employees today across five states.

And we think this -- I wouldn't call it experiment, I think it's a real restructuring activity we've taken on to be competitive, we knew we weren't, and they're doing a great job.

So it gives you some sense of it, Guy, without too much.

Cost structures are coming down.

Thank you.

Theepan Jothilingam, Nomura.

Just a few questions actually, please.

Firstly, just coming back to the PSC settlement, I just wanted to understand how you thought the admin charges would progress through this year.

Is it right to think that now with the BEL claims and that deadline past, that charge starts to drop away?

Secondly, just coming back to oil projection and FID, you talked about the reengineering on Mad Dog.

Is that still a 2015 event in terms of sanctioning?

And what type of price do you test down to?

What's your low case now in terms of oil prices per sanctioning?

And then thirdly, Bob, I guess a concern for investors has been that you discuss selective acquisitions.

Can you just elaborate on what you think is the right type of strategic deal for BP scale type?

And if you are in the lower-for-longer camp, is it right for BP to do a deal in the next six to 12 months?

Maybe I'll just pick up that first question on the PSC settlement, where we've taken additional administration charge to this quarter, Theepan.

We've now provisioned out to the end of 2018.

If you look at the total number of claims still yet to process, there's still just about over 50% of the total claims still yet to be processed.

We saw a big, big, uptick in the last 10 days before the June 8 deadline.

It's not clear what the quality of those claims will look like as the administrator works his way through that.

But we are working with the administrator in terms of the administration of the costs of the PSC settlement and, of course, we do expect that to taper down by the end of 2018.

But we've now fully provided what we believe to be the right level of administration costs, going forward.

Now it's simply a matter of what the business economic loss claims look like.

And it'll probably be another couple of quarters before we actually have sufficient actuarial data to make assessments on that terms of forward provision.

But we'll continue to review that each quarter.

And, Theepan, Mad Dog, as you know, is a second phase of the Mad Dog field in the Gulf of Mexico.

It's a very prospective project that we've been working now with the settlement.

I think it's clear about our investment plans in the United States.

We're working with our partners there.

As we've retooled and reengineered that project, the costs have come down substantially.

We'd said at one time we may FID it before the end of the year.

I think where we are now it could be towards the end of the year; it could be early next year.

What we're finding is we see the deflation costs coming down.

What we have to decide is at what point do we say they're going to continue to come down.

We're just going to try to optimize the economic point of the FID, but it's still very much on the cards.

And in terms of acquisitions, it's never a good idea to talk about acquisitions, or scale of acquisitions.

I think what we will continually do is scan and screen for deepening in existing projects as a starter.

I think that simplifies our activities without adding the overhead.

That's an obvious one.

And commenting on acquisitions, I think probably the bigger point for us is thinking about value over volume.

So we're going to pursue the value, and I think we'll just see.

I think the landscape is quite uncertain in the industry and it will be for some time.

And that will drop all kinds of challenges and opportunities for companies that are well positioned for it.

That's probably all I should say, Theepan.

Okay, fair enough.

Can you give any sort of parameters on what you're testing down to in terms of project economics?

Yes, sorry, I forgot.

We are testing our projects, believe it or not; we're certainly testing them right now and looking at decisions around the $60 mark.

We're, of course, looking at it at $80.

We even did a little stress test down at $40, but we think that they probably don't accurately reflect the cost structure today.

So right now, we're looking at these around the $60 mark.

Thanks, Bob, very helpful.

Oswald Clint, Bernstein.

Bob, I had a question really on Russia, and this kind of strategic move into East Siberia.

I guess it's not a big part of Rosneft or TNK previously, so what's changed to make you move over to that region where, of course, the geology is a little bit different?

Can you talk about maybe how big you think this becomes?

Could it become a new hub?

And does it really fit into that category you were mentioning about near-field exploration, pulling volumes through much faster?

And then secondly, maybe a question for Brian, in terms of the Lower 48 again, in terms of your separate disclosure, I think you're saying $8 or $9 a barrel production costs, which, when I compare that to $40 or $50 other E&Ps looks pretty good already, at least versus the average, $2 or $3 less.

So the question is, have you really pushed -- it looks like you've done quite a bit already, or is there a significant further movement on that number?

Thank you.

Oswald, I'll take the question, and then Brian.

Actually, Oswald, if you look at the East Siberian oil basins around in that area, there is significant activity by Rosneft out in that area.

TNK-BP had a very large field out there called the [Verkhnechonskoy] field; now it's part of Rosneft and it is an area where the East Siberian pipeline goes through.

So there's quite a bit of discovered fields out there and an additional exploration [AMI] seems very appropriate, given the basin geology.

And of course the heartland, the very, very, large Western Siberian basin, which is where everybody's big production in Russia is of all the companies.

We have signed two areas of mutual interest there, which is about 265,000 square kilometers, two very large areas there, and where conventional oil exploration out there as well.

So we see both of those as key to the activities of Rosneft, and for BP not wanting to just be a financial investor in Rosneft, to partner with them.

Oswald, then in terms of Lower 48, you're right to highlight it from disclosures.

It's down 6% in terms of production costs, and we would continue to expect that trend to continue to decline with the new team that we've got in place, the new approach that we have to Lower 48.

I think there's more to follow on this, and you'll see that as the next four or five quarters progresses.

But we are narrowing that business in a very, very, different way to the way we were before.

Okay, very good.

Thank you.

Doug Terreson, Evercore.

I have a couple of questions.

First, because right-sizing the cost base is obviously becoming a pretty important objective, especially based on Bob's tone and comments today, I just wanted to see if there are any metrics or different markers that you guys have related to the different divisions that could provide a little bit more specificity.

Meaning, we talked about Group cash cost earlier, but is there any color that could be provided on the different divisions to just give us some insight, going forward?

Doug, it's Brian.

Probably one of the biggest indicators, which is one of the tough areas for us, is around headcount.

As I said earlier, we started this in corporate restructuring phase, where we're seeing significant headcount reductions, both in terms of our own employees but also contractors, where we tend to run a bigger contractor workforce in places like IT&S.

Then if you look at the two divisions, you're also seeing significant headcount reductions, both in upstream and downstream, as we progress through the year.

And I think you'll see more of that before we get to the end of the year, hence the larger restructuring charge.

Then if you look at various metrics in terms of benchmarking, we are also seeing improvements.

Lower 48 was one example, but across the piece we're looking in terms of how we drive deflation through the system.

Okay.

I have one more question.

An important thing for the Company over the past several years has been value over volume; I think it served you guys well.

I think Bob mentioned a few minutes ago that that would remain the relevant thing for strategic activity as well, that is if they were to materialize.

When you guys think about this phrase, value over volume, what specific criteria are you referring to?

Meaning, what's most important for the Company when it thinks about capital allocation today and also strategic activity, if it materializes?

Yes, good point.

It doesn't mean that volume growth isn't something that we will strive to do.

We actually believe that we can see the potential for production growth between now and the end of the decade out there.

But what it really means is that we're going to strive for every additional marginal barrel of production to have a higher margin than our existing portfolio, so that we bring up the margin of the entire portfolio with the decisions that we make.

We have, by necessity, had to divest $45 billion of our assets.

But actually, what that has done is allowed us to focus our portfolio and increase the average margin of the portfolio.

The 15 major projects that were brought on from 2011 through 2014 had twice the margin of the existing portfolio.

So I think that's how we'll think about decisions that we have to make.

Of course, there's a cycle in the oil prices; you have to make a call on how you evaluate them.

Then in terms of strategic steps or other things, or deepening in projects, I think that's a good-for-all-seasons philosophy.

I think we got on a treadmill of driving production rather than keeping our eye on the margins.

Now, we are a believer that there is value, and I think the world has played itself out since 2010/2011 that vertically integrated companies have a role here.

We're seeing the Group benefiting from strong downstream margins, a very focused downstream portfolio as well that moves through the cycle.

We think that not only is that a countercyclical benefit, but we really do see the linkage between our upstream and our downstream, and what I think is a very skilled trading organization as well.

Great.

Thanks for the elaboration, Bob.

Thomas Adolff, Credit Suisse.

Two questions, please; one on decline rate and one on your four Ds, divestment.

Firstly on the portfolio decline rate, back in December at one of your breakout sessions at the Upstream Day, you said that the portfolio decline rate is around 4% to 5%.

Presumably, that was based on a higher spend on Brownfields and, obviously, you never gave an exact split of where the CapEx was cut.

I wonder whether that 4% to 5% is still the case, or whether that's still too early to say, i.e., the effects from a lower spend.

Or are you just successful in maintaining that range, as you say you're getting more from existing assets from a lower spend.

Secondly, one of your four Ds, divestments, and feel free to correct me if I'm misquoting you, I believe beyond 2015 you used to say the disposal plan should be around $3 billion per annum.

A normal portfolio optimization approach, which obviously would also then come with acquisition on this organic -- you're successful in adding resources.

But if you look at this $3 billion per annum figure in this environment, in the context of a leaner portfolio since Macondo, is that something you're still confident you can achieve?

Thank you.

Thomas, maybe I'll just take that last question, in terms of $3 billion.

I think the number we used before is $2 billion to $3 billion of natural churn, which is what we've done historically and see no reason why we wouldn't do that on a point forward basis.

So it's still giving indications of around $2 billion to $3 billion in a portfolio of our size.

I think all you're seeing is it's a different mix of assets now than those late life assets that were higher returning, highly depreciated assets that you saw in the $45 billion program.

We're now seeing some early life assets that actually aren't in production; things like the [Paleogene] we did at the start of this year.

So it will be a different mix, going forward, but we'll continue to look for churn $2 billion to $3 billion of the portfolio each year.

Thomas, on the decline rate, I think I'm going to take your point, which is a good one, all the way back to your reminding the obvious; it's safety is good business.

And all the turnarounds that we did in the Company from really 2010 up through 2014, which was an enormous program, has led to some of the best operating efficiency we've had in the Company.

The months of May and June were 95% operating efficiency of our upstream assets.

The North Sea, in particular, has come up in its efficiency, and the Gulf of Mexico has been working well, though we had the normal turnarounds down.

What that has done is allowed us, and I just went through this, the base production management, those decline rates now look actually a little better in the sense that we're seeing 3% to 5%.

We said 4% to 5% in December; we're actually seeing them around 3% to 5% possibly as well, so all of that leads to the good operating cash flow.

It's sort of a virtuous circle: safety; reliability; uptime; efficiency; more operating cash flow; and then maintaining the base.

Perfect.

Thank you very much.

Rob West, Redburn.

I've got a question on some of your Greenfield projects, [just three] in particular.

I guess there's a spectrum at the moment of things that were designed and contracted and locked in, say, 2012 and 2013 and can't really flex that much in terms of development plan or the contracts and things like Mad Dog Phase II where it looks like even since December, further costs have come out from renegotiating contracts and redesigning the [workforce].

How should we think about three big Greenfields, Khazzan, Shah Deniz and the West Nile Delta in that context?

Since they were effectively sanctioned in the last year, are they in a category of things that can move in terms of cost, can move in terms of design?

Or should we think about those as the budget is totally locked in as what was announced?

Then my second question is on gasoline, where the cracks have been strengthening relative to diesel.

I think you're one of the more gasoline-heavy of the majors.

Is there any change in the configuration of your refineries?

Can you get more yield out on the gasoline side and have you taken any steps to do that already, or do you see the margins just normalizing in the second half of the year?

Thanks very much.

Yes, okay, Rob, a couple of things.

Well, one thing we've learned over time is what we don't want to do is, in the middle of a project, change the scope.

So when you look at projects that are, essentially, pretty early here, West Nile Delta, we reengineered that for several years, and we are -- in fact we FID'd that in the first quarter.

It's a big project, 5 tcf of gas; we think it'll be on stream 2017/2018, and it'll use existing transportation process infrastructure there.

We are seeing deflation come through.

We just went out and spudded the first well on the developments side of it, and the rig rates are very attractive.

So I do expect to see that coming through on projects like West Nile Delta.

Shah Deniz, we sanctioned that project at the very end of 2013, so it was during 2014.

We have seen deflation come through on a variety of things, from even the steel in the pipelines to -- it's a little bit harder for drilling in the Caspian because it's sort of a land locked sea, to an extent.

But right now, that project is under budget and ahead of schedule, which is good.

And in Oman, which is nearly 300 wells over 15 years, we're certainly seeing the deflation coming through in the cost of the wells and in the processing plant there.

So the ones that we have in train, those big three ones that you talked about, to varying degrees, West Nile Delta we'll see a lot.

Shah Deniz, a reasonable amount, and because it's onshore in Oman and not offshore in the yard somewhere, it's definitely going to see cost deflation as well.

Then in terms of refining and our ability to switch yields, there is some degree of yield switch.

We can flip between 4% to 5%.

I'm not sure we're that much more gasoline heavy than the rest of the industry.

We have got a much smaller footprint in terms of refining portfolio, having got out of somewhere close to 13 or 14 refineries over the last 13 or 14 years.

We're now down to a portfolio of assets.

We've got some inside that portfolio, like Cherry Point, which is heavily linked towards diesel, jet fuel.

But in terms of the ability to move some of the yield, it's sort of the margin.

I would also say that at least 2Q refining margins that we've seen have been very strong, supported by strong gasoline demand, and tight product supplies on the West Coast.

But actually, we see some of those correcting as we get through 3Q and 4Q.

That's really useful.

Thank you.

Chris Kuplent, Bank of America.

First question is on CapEx.

I just wanted to understand a little bit more about your comments, Bob, where the savings have come from.

You've got a range there, I guess, somewhere between 10% and 20% on average; can you translate that maybe to your current CapEx budget, which you set out at $20 billion for this year?

Now you're seeing it already lower.

How much of that CapEx budget, as you look forward into 2016/2017, has now been, you would say, satisfactorily renegotiated and is committed?

That would be helpful to get an idea around remaining flexibility as we look out.

And I guess the second question is simply a boring question, sorry, Brian.

I just wanted to come back and ask you, halfway through the year, whether you can comment on your full-year guidance on things like production, which was meant to be flat, year on year, D&A and all those other lovely items you had in your full-year results presentation.

Thank you.

I'll take the more colorful one, the CapEx deflation.

Thanks, Chris.

Well, we don't think we've seen, by any means, the deflation that's yet to occur.

As the world moves into what I think does look lower for a period of time here, typically, if you go back in some of the other cycles in time, 1986 and then the late 1990s, deflation impact, typically, occurs with a lag of one to three years, depending on the market, the maturity of the local market, the regional market.

I think our historical analysis shows that our cash cost should be able to come down 13% to 14% and 20% deflation for capital cost by 2017.

We think the development costs for new projects, which have the rigs in there, we think they will deflate by as much as 20% to 30%.

Of course, it's much less for projects where we've negotiated the prices during the term.

But with these things like Mad Dog coming up, and these just-started projects, I don't think we've seen the end of the CapEx.

I know you're trying to look for what is the CapEx level to model 2016/2017 for the same level of activity.

I think we're not quite sure there ourselves, but we are seeing this deflation come through.

We're going to continue to drive it; I can give you some color so far.

We have seen about one-third savings on subsidy installations at Thunder Horse in the Gulf of Mexico expansion project, for example.

We've seen 30% rate reductions for the North Sea Mungo field drilling.

We've seen 20% reductions from Sumitomo in pipelines; they're back to 2009 pricing levels.

About a 20% savings on the subsea hardware for Egypt in the West Nile Delta project we talked about before.

And I've got a number of other examples here: 10% rate reductions on well services; 20% down on tubulars.

And these are still moving, and some of them were locked in before, but these are the new ones and, as time goes forward, we're going to see these come through.

I think we're seeing a bit cost rebasing of the entire oil and gas industry now.

And we used to make money at $60, we used to make money at $40, we used to make money at $25, but it's going to require this rebasing of costs, which I think is now firmly in the whole industry's sights, Chris.

Okay.

Thank you.

Chris, and then in terms of guidance, no major changes from what we laid out for you at the start of the year, other than the capital piece we gave you, which is before we'd said around $20 billion dollars as we were sizing the program for this year.

We've seen the deflation come through, as Bob just described.

We're still in the middle of that process, so we're now confident to say it will be below $20 billion for this year.

In terms of production guidance, it still remains broadly flat with 2014 is probably still appropriate.

That said, I think the 2Q turnarounds went extremely well in terms of bringing our production back on stream, especially in the Gulf of Mexico.

Reliability has been running well; again, that gives us some confidence in terms of the piece Bob talked about around the turnaround program historically.

But then we also have the hurricane season, which we know 3Q last year was not that heavy a downturn in terms of volumes as a result of the hurricanes.

I've no idea what will happen through the third quarter, and really, that will probably determine where we end up in terms of this year versus last year.

But I'd say, broadly, flat is still a good recommendation.

There may be some upside, but a lot of it depends on the hurricane season.

Okay, thanks.

And you would say all the other items as is?

Yes, no other changes other than what we've already flagged on capital.

Okay.

And just on that point, would you be strongly advising us against annualizing your first half $9 billion-plus [accounts] for the full year?

I always try and strongly advise everyone never to take a quarter or a half-year and multiply it by the remainder of the year.

But I think below $20 billion is now a confident -- I can confidently sit here and say we believe it will be below $20 billion.

Okay.

Thank you.

Lydia Rainforth, Barclays.

A question just following up on Chris's, actually.

On the cash costs, Bob, are you talking about those being able to come down 13% to 14%?

If I look at the chart that you showed, it does have 2015 first half being similar to first half 2010, and yet the production base is close to 30% lower than it was at that point.

So is that 13% to 14% on a unit cash cost basis that we're looking at?

And then, secondly, on the chart of the renegotiations that you've had so far, what percentage of contracts does that actually cover that you've renegotiated?

And the final one is just on the dividend.

And where you say dividend and focus on the rebalancing the financial framework, is there anything on a two to three year view that you think will stop BP from being able to rebalance that financial framework to be able to support the current dividend?

Thank you.

Yes, Lydia, on the cash cost question, what I was referring to is sort of our historical review of the deflationary cycle that if you look, over time, unit costs come down 13%.

So that's a little bit of a theoretical point of looking at history of what we've seen in the past during downturns.

To be honest, our Company became overly complicated by necessity after the accident.

We put in place multiple safety operational risk organizations, parallel review processes, decision making, that I think we have our confidence back now.

And I think we have even greater potential to reduce our cash costs, going forward.

So one was theoretical, based on history of the industry, and I think ours, you'll continue to see them come down.

On the dividend?

Yes, in terms of dividend, it really is a basis of, as Bob said, this industry works at $25/$40/$45/$50/$60 dollars a barrel; it's a question of how fast you can get deflation back into sync.

We've got a very strong downstream business that's very cash generative right now; the upstream is cash generative, very cash generative in the second quarter.

We were actually in surplus cash in the second quarter with the -- and actually our net debt came down as a consequence.

That's no indication for the next two quarters.

We continue to look at what the trend is on deflation, but one of our primary goals, going forward, is getting everything back into balance and ensuring we can support the dividend that we have in place today.

And, Lydia, just to clarify the cash cost charge is absolute cash cost and it looked flat in 2014 because it's only the first half of the year.

In fact, we did see a reduction in cash costs in 2014 which was weighted to the second half of the year.

Fred Lucas, JPMorgan.

Bob, a question around the potential for further structural change to your upstream portfolio.

As you look through your lenses into a lower for longer price setting, where within your upstream portfolio do you think BP is either over or underexposed, either by geography or asset type?

Well, Fred, I think it's a little easier to answer after the $45 billion of divestments.

So we have a lot of its moved away.

I think where we can always add to, I'm not saying we're underweight, but we can focus on and should focus on is near field opportunities around our existing hubs and infrastructure.

That's clearly a real opportunity for us to focus on.

Mad Dog is an example of that; in fact, some of the Russian projects there are near infrastructure is another example of it.

I think the portfolio we've built over the last three years, in terms of shrinking it down and compacting it, is actually pretty balanced.

I don't see an area that I feel like we obviously need to move away from because its high cost.

I would feel differently if you were asking me that question with the portfolio of three years ago.

And right now, again it's the value.

If we see the value in all parts of the world around something that fits the portfolio, we won't stop there.

But you won't hear me say something like, well, I think we need more LNG, or I think we need more conventional or unconventional gas.

I think it's really just how the opportunities put themselves up.

And if we've got a strong balance sheet, we've got certainty now in the payments from the Gulf, we can rebase the cost structure of the Company, I think we'll be well suited for opportunities when they come along, and I think there will be some.

Okay, thanks.

Second question for Brian, please, around cost deflation.

It feels like, were you to represent the chart you've shown us today in six months' time, those bars are going to get broader and move deeper, i.e., deflation is still building and I think you've said so yourself.

If we just draw a line through the middle of those deflationary numbers today, around 20% and assume not too much of that is getting caught in the CapEx budget for 2015, why wouldn't the CapEx budget of $15 billion be appropriate and realistic for 2016?

Is that for the Group, Fred, or for upstream?

That's for the Group.

Yes, I don't think you'll see that level of deflation coming in.

On the cost base, I think we've still got more to flow in the second half of the year, hence why the bigger restructuring charge we've taken.

So I think there are more costs on the [revec] side to come out.

(multiple speakers) CapEx here, Brian.

Yes, but on the capital side, I think it's now into the tough decisions about I think over the next 2016/2017/2018 and even 2019, those projects are baked in.

Bob talked about some deflation even we're seeing in those existing projects like Shah Deniz Phase II, and [Khazzan], and West Nile Delta in terms of Egypt.

But then we go into some hard decisions about the growth of the Company beyond 2019 and making some of those tough choices around capital versus rebalancing books.

And I think around where the market is there around $60 a barrel, I think we can comfortably do both.

I think $15 billion would be way too low, not that I want to give you guidance now for next year, but we'll need to see where the deflation comes out this year and then give you some further guidance as we go into the first quarter of next year, Fred.

But I think $15 billion would be way over cooking it in terms of what we're seeing in the market.

Fair enough.

And just finally tactically, do you have a line of sight to see or say when you think deflation might peak?

I'm just wondering, tactically, when we might start to see you get closer to more project sanctions around the bottom of the deflation cost curve.

Yes, that's a great question, Fred, and I think you'll see more of that as we go through the third quarter results in terms of the bottoming out of deflation.

But I think it's just too soon to say.

Do you think we might bottom out before yearend?

Couldn't tell you, Fred.

Tell me what the oil price is going to be.

Current oil price?

I think you won't see it bottom out until next year, 2016.

Yes, I agree with that.

Okay.

Thanks very much, guys.

Biraj Borkhataria, RBC.

Most of my questions have been answered, but I had one on your comments on a strategic shift to gas.

Maybe you could just give us your outlook on LNG and how you see that fitting in your portfolio, and in particular, how you're assessing your potential new projects in LNG?

Thanks.

Yes, Biraj, LNG economics have been challenged, but there is real deflation coming down now in some of the LNG projects.

We've just started the front end engineering to decide whether or not, down the road here, to FID the Browse project in Australia is one, but we've already seen indications of significant drop in the CapEx projects.

The other ones that we have -- and we have also been waiting before we take the step, for example the expansion of the Tangguh project in Indonesia, the third train on that.

I think by delaying and not moving forward so fast we're going to see deflation come through in that, and we'll consider that as an expansion sometime next year.

But these are exactly the kinds of projects that are going to allow us to fine tune and make decisions and have options for the future.

I do believe that gas demand, we're going to see -- by 2035, we're going to continue to see the growth in both gas and oil.

There's no question there's going to be demand that will be out there in Asia in particular for these LNG projects.

It's just a matter, I think, of getting the timing right, and getting the costs right.

And I'm hopeful that next year, we get on the Angolan LNG project which has essentially been built, it just needs to be refined, and get that on as well.

Thanks.

Very helpful.

Thank you, and thanks to all those that are still waiting patiently.

Alastair Syme, Citi.

Can I ask you a couple of short questions on dividends and returns?

I think, in an earlier answer on dividends, that they were put in the context of the cash balance.

I'm wondering if you could put them in the context of through-cycle returns.

So put another way, what return on assets do you think are needed to be delivered in the investment cycle to support and grow real dividends?

And then the second question, given your frame on oil price it's probably the more conservative end of the industry; where you joint venture with other companies, do you think your approach, your criteria, is making a move forward at a different pace than some of your peers?

So, Alastair, on the first question, I think long-run returns can only head in one direction from where we are, given what's happened with costs.

And having gone from $100 a barrel down to $50, obviously you've got the big chunk of revenues missing.

But as we now start to focus on the sort of projects that Bob was talking about, they're naturally going to be biased towards high returning assets first as where the portfolio are.

So that will be a big focus, and that is what will give us confidence to ensure that we can continue to underpin the dividend, going forward.

So returns is a big part of what we're looking at in terms of the current portfolio projects, and those things that we'll pursue over the near term and medium term, with a very key eye on the long-term future and long-term growth for the Company.

Yes, Alastair, your point about oil prices, we may have been bearish.

I sort of feel that we're not alone now, for sure.

What we're finding in our joint ventures, and even in consideration of new projects and concepts, and working with the engineering teams, whether it's Mad Dog with BHP and Chevron, for example, great partners, I think everybody is now looking at costs very, very hard, driving it through in the capital costs, the suppliers are moderating.

So I don't feel that we're having a difficult time slowing things down, or moderating pace, other than the fact that we're driving very hard in our joint venture projects to make sure the cost structures are changing.

So I don't feel like we're out there on our own now, Alastair.

And I would say that the approach of rebasing the cost structure for us, simplifying BP, which is something we really need to do, and have been working at very hard, it's a good-for-all-seasons thing, in any case.

Can I come back to the first question, just briefly, if you look across BP there's a dividend payout, I guess, measured against operating cash flow is higher than it used to be.

Is the implication that your hurdle rate on new investment is also higher than it used to be?

I think, in terms of how we look at the hurdle rates, going forward, we still work on the same range that we have historically.

It's more about how the cost base now catches up with where the oil price is.

I'd actually argue, Alastair, that you could say that certainly for the sector, and for BP it's for different reasons because we sold off a big chunk of high returning assets, that the sector is trended to 10% returns at $100 a barrel, which tells you that the cost base was above $100 a barrel, or more capital was being layered in to future investment that wasn't in service.

And I think, as we start to correct the portfolio, going forward, with the focus on the lower capital appetite being driven [a bit] by deflation, some activity, you'll start to see those returns drift back up again.

But that is one of the main drivers that we see over the near to short term.

Thank you.

Asit Sen, Cowen and Co.

I've two quick ones; first on Lower 48.

Brian, thanks for providing all the information on the financial data, particularly the production costs for BOE.

Just wondering if you could provide us with the DD&A per BOE for the Q1 and Q2, if possible.

And second, doing quick math on downstream free cash flow for the first half of this year, and using a historical downstream DD&A and a tax rate of 35%, looks like around $3 billion in cash flow, fairly impressive.

Thinking about the potential upside outside of the macro, could you talk about where we are in the multiyear $1.6 billion of cash costs efficiency program?

And also, any thoughts on the impact of the China PTA plant that just about started?

So on the first question, on Lower 48, we don't provide the DD&A data, hence why it's not in the updates.

So that isn't something which we include in the disclosures right now.

On free cash flow, I'm guessing that they're certainly not our figures, because we don't give you free cash flow figures by sub-segment.

We look at those at the segment level.

But you're right, the downstream is a very strong free cash flow accretive part of our Company, and has been through the cycle.

It's one of the parts of the business that we run for cash and, therefore, it's free cash accretive.

And then in terms of the $1.6 billion efficiencies, Bob layered out, I think, in his presentation, different components of how that's now starting to flow through, and we have seen that flow through the first half of this year.

Yes, Asit, I'll add on the $1.6 billion restructuring in the downstream, the annual cash cost efficiencies by 2018 versus the 2014 baseline and where we are in that, I'll just note that these restructuring programs, a lot of them have to do with labor flexibility and geographies.

And labor flexibility and ability to restructure quickly is faster in the US; it's faster in the UK.

It takes longer in Europe, so I think we've got restructuring going on in both those areas, and I think it's going to be first in North America, UK, and then following on in Germany, primarily.

On the PTA plant in Zhuhai, it's an incredibly efficient project.

It's probably one of the most energy efficient projects.

It's got a capacity of about 1.25 million tons a year and we use one of our proprietary technologies that are there; it's called ISOX.

It's probably going to have the industry leading manufacturing costs.

PTA has been over-built.

It's a industry that's been somewhat stressed, but I think this is a really nice addition to the industry.

It should be probably the most efficient unit possibly in Asia, in the world.

Don't know if that helps, Asit?

Yes.

Thank you so much.

Lucas Herrmann, Deutsche.

Just a couple of quick ones, if I might?

Firstly, Bob, going back to Mad Dog, did I hear correctly that you mentioned costs had fallen by, I think, 50% from the original costing and, from memory, the original costing I thought was $14 billion so you're suggesting that that project now is trending around $7 billion?

Secondly, could you just talk a little bit more about the Gulf and your production expectations, aspirations, this year going into next?

And I guess I'm just glancing back at the Sunbury presentation two years ago when I think you intimated the Gulf, after removing the disposals you made, would be doing somewhere around [$260 million, $270 million] this year, and just whether that's a realistic number or ambitious now.

And maybe contrast it a little bit with what's going on in the UK where the performance appears to have improved fairly markedly over the course of the last six months and we're seeing good volume growth.

And sorry, finally, just since you mentioned Zhuhai, does it make a profit at current PTA prices, or will we just be looking at a cash contribution at this stage?

Right, okay, that's a wide spectrum there.

Yes, let me pick up the last one because that's probably the easiest one.

We don't give you profitability by asset but it would certainly be cash accretive.

Okay, Brian.

Thank you.

That's right.

It's really just come on in the first quarter but, yes.

Now, Mad Dog, depends on the point in time, the $14 billion, but at one point in time, sometime probably 2010, 2011, the Mad Dog cost estimates were as high as $22 billion for the project.

It's been recycled now and I think all I'll say, because we're still talking about it with partners, but it's $14 billion down in December 2014, and we now believe we can get that project done for under $10 billion.

And in the Gulf of Mexico, I don't know if we gave it out exactly what the full year was last year, but the fourth quarter [$260 million] or so.

Going in this year, the first quarter, above [$250 million]; we've got the turnarounds going on right now.

I think the growth will come through the Thunder Horse South expansion down the road, the Thunder Horse water injections.

We've got the Ursa, Mad Dog recoveries out there.

I think being able to keep this running and getting up to [$270 million] by 2018 is very much in our sights.

And the North Sea, which was, as many people said, the problem child of the offshore oil and gas industry globally because of the efficiencies which were running around 65% a few years ago as an industry, for us, we've taken our plant reliability up from 75% in 2012 up to around 82% now.

And in the Norwegian side in 2012 we were running about just under 70%, and now we're up to 92% so far year to date.

So the North Sea is a very challenged mature basin that is responding very, very quickly to the challenge this year.

And I think reliability for the industry is going up.

Okay.

Both of you, thank you very much.

Gordon Gray, HSBC.

Just one thing left to ask, actually.

If we take aside the strength that we've seen in refining margins, you have a refining business which is top quartile, which is running at 94% utilization.

Is this as good as it gets, i.e., what other levers do you have, for when margins inevitably do come back, for improving the underlying performance of that business further?

You're right to flag that; actually, it is running at a very high utilization.

There may be still some more road to travel in terms of across the whole portfolio.

Some of those assets are operating at 98%, 99%, so right at the top end.

There's still some room for improvement, but there's other things around commercial performance inside those refineries: how we set them up to run, the commercial side of it, and then how we interact with the trading business.

So I think there is still road to travel in the downstream, if you look at what Tufan has done with the business, both in terms of cost but also on the revenue side.

So I think you're right to flag it.

It's at the top end, but there are some assets performing significantly above that and, therefore, there is some more room to travel.

Okay.

Thanks.

And the fuels marketing outside of that, the networks, the retail networks, there's efficiencies still to come from that part of it, because we think of it as a fuels value chain, but it's great to have these assets running 94%.

This is what we want.

Yes, absolutely.

Anish Kapadia, Tudor Pickering Holt.

I was wondering if, on the cash flow side of things, you saw underlying cash flow lower in 2015 than 2014.

And again, just looking back at your 2014 targets, I saw that your underlying earnings were 14% below your target, but your cash flow was 9% above.

So I was just wondering if you can explain that; were there some one-off positives on the cash flow side last year that won't be repeated this year?

Secondly, just on Angola, I was wondering if you could confirm that the 2015 pre-salt wells that you were drilling were unsuccessful?

I haven't seen anything around that.

I'm just wondering how the outlook for Angola looks now, given some disappointing exploration and probably having moved through the infill drilling and [tieback] program.

And then just the final question was on, you mentioned moving up to 10 rigs in the US.

I'm just struggling a bit with rationale over there, when you're seeing just over $25 per barrel liquid realizations and $2 gas realizations.

Thank you.

So maybe on the first question around the operating cash, you may recall that in 2014, we did have a $2.2 billion working capital release, which underpinned the operating cash flows for last year.

This year, so far in the first half, we've had a $1.4 billion build, so that's a swing of somewhere from $3.5 billion to $4 billion just on working capital.

I'd expect the $1.4 billion build to be released through the second half of the year.

On underlying operating cash flows, if you adjust for the environment and the price, actually, they are coming on year on year stronger, in terms of if I go back and look at base revenues across the businesses, correcting for the environment and the oil price.

So actually, we are seeing a strong set of operating cash flows coming through this year.

That will get stronger, as we see the costs flow directly through to the bottom line and through to cash in the second half of the year.

Anish, on Angola, we drilled two wells in Angola this year, Katambi and Pandora.

They're both still under evaluation, so I think best not comment on that.

We're working with partners on that.

And on the rigs in the Gulf of Mexico, we have eight running now in the Gulf of Mexico.

We've got a couple of them working on Mad Dog; we've got a drill ship working on Atlantis; we've got another -- we're working on Atlantis.

These are high performance wells for us.

We've had one exploration rig that's been working on [Hela] side tracks there.

And we've got three of them working on Thunder Horse.

I'm talking about in the Gulf of Mexico, which is your question.

Did you ask a question about Lower 48 as well?

I was actually referring to -- I think you mentioned you were up to 10 rigs on the Lower 48 and I was just wondering, given where the realization has been extremely low at $25 per barrel liquids realization, I was just wondering how it makes sense to do that.

I think the big change that we're seeing there in term of Lower 48 is a 50% reduction in the drilling costs.

So as we've brought those drilling costs down, Dave and his team have been able to ramp up the number of rigs we've actually got working down there.

And if you then look in the basins that we're in, that has actually changed the profitability of the portfolio that we now have in the Lower 48.

So it's absolutely being driven by the fact we've reduced the drilling cost by 50%.

And I think a big focus on the Anadarko and Arkoma basins, which we get nearly 20% liquids from it.

Stephen Simko, Morningstar.

Just one quick question, as it's getting pretty late.

When we look at, or thinking about, downstream CapEx and where it's going to trend with the Whiting commissioning you've done and the recent spend, all that happened over the last six, nine, 12 months, what would be the right way to think about past 2015, as far as what the base case spending level would be, as well as any adjustments you might make depending on commodity price movements from here?

Thank you.

We don't typically publish CapEx by sub-segment, but you're right to flag the fact that downstream's capital is significantly lower than the most recent run rate.

With now the Whiting refinery fully commissioned, the capital has come down quite significantly, and I think it'll expect to run at round about the levels that we see today.

We'll look at strategic opportunities, in terms of infill, as Bob described round the fuels marketing business.

As opportunities arise, we'll look to do that.

But I don't think you should assume any more big projects on the refining side in terms downstream over the short to medium term.

We're pretty comfortable with the portfolio that we have.

So you're right to say CapEx will be trending lower, is lower this year, but we'll continue to look at opportunities, going forward.

And in addition, the Zhuhai project is also completed.

So there's a couple of big projects that are now on stream.

Richard Griffith, Canaccord.

Sorry to drag you back to the cost issue, but I was just wondering, you've talked a lot about the deflationary environment, but I was wondering to what extent are you going to be able to lock in any structural changes from simplification, standardization, etc., that a lot of players have talked about in the industry, as opposed to us just going through a more cyclical downturn that may inevitably go back up with a higher oil price.

Well, Richard, that's exactly the questions we ask as we go through the changes that we're making.

We have structural changes, organizational structural changes, that we're making to simplify the structure that we think will be sustainable, most certainly in the upstream.

And so that, again, is good-for-all-seasons here.

We've become very complicated, so a reduction in terms of decision making, how we do it, numbers of people to get things done.

We think we have a lot to [run].

That's absolutely sustainable.

I think the deflation, once we move this in, there are elements of it that may not be sustainable, because that's what history shows in a commodity with a cycle.

But we're working to change our Company to make sure we're not so complicated.

And standardization is a very good point.

We, as an industry, have wanted to design serial number 1 for many things on many platforms for some time now.

We're driving now a single kind of wellhead that we can use in different places around the world, standardization of equipment, standardization of activity, and that's starting to link up between the companies as well.

So there was a period of time where everyone had their own way of doing it.

I think people are moving very, very quickly now and we're part of an industry group now working on standardization of some of the big pieces of equipment to try to do just that.

And sorry, if I might, just if you took Mad Dog Phase II as an example, what proportion of that 50% capital reduction you've talked about be equivalent to the standardization simplification as opposed to some of the more cyclical factors?

Well, some of it is the big scope of the project itself, what we were trying to do.

We've looked at simplifying the design requirements, the wellheads, even the phasing of the project, looking at Far East fabrication options.

I think, one is a big change in scope, and a second part of it is just agreement of what we've learned over the last few years on standardizing wellheads, equipment, drilling, completion designs, that sort of thing.

All right.

Thank you.

Jason Kenney, Santander.

I'm going to ask my quarterly question on Russia, if I can?

[Saw a] year-on-year downshift by about 50% for the Russia division, but the second quarter versus the first quarter is up 2.8 times, and if I remember correctly, in the first quarter you said there was already big FX support in the first quarter.

So I'm still struggling to get how that Russia divisional number comes in, and I appreciate that you've still got sensitivities because Rosneft hasn't reported.

The second question, if I can just ask you that as well?

On the US Gulf of Mexico settlement, you mentioned you're going to be paying something in the coming weeks; should we be thinking of that kind of annual number that was defined in the settlement press release?

Should we be thinking of it as an annual payment, a one-off annual payment each third quarter or each fourth quarter, or is it something that is paid quarter to quarter to quarter for the next 18 years?

Let me pick up the Russia question, which is probably the easy one of those, Jason, in that we can't really provide any detail.

But the components that would make up the mix, on our estimates of what we can see, and of course, it's really for Rosneft to sort of come back with the actual breakdown, the different components Q1 versus Q2 will be round, one, we know the euro's price improved, so that's out there, you can catch that.

You know that there will be a positive GC lag, given what happened to the oil price through the quarter versus previous quarters.

You will then -- we've made estimates of what we think the ForEx hedging piece will do around their debt book in terms of what they load in place around ForEx accounting, and then there will be other movements around provisions.

So really, it's a question for the Rosneft results, but they're the big components that we can see moving round that would explain the result quarter to quarter based on our estimates.

That would be the first point.

On the second --

Are you ever going to be able to get a rule of thumb for that?

That's really a question for Rosneft, and I think that's highly unlikely, given the amount of moving parts that you've got.

It's difficult enough trying to get a rule of thumb for our own portfolio, never mind for that piece.

Jason, I'll just put a footnote on what Brian has said here.

The duty lag, which is really not always easy to model, we had exactly the same problem -- well, not a problem with TNK-BP, but what happens is in Russia, the duty lag means that the tax preference price is set a quarter or a period of time before the period measured.

So when production falls, it often gets hit with a higher duty percentage and then, when production rises, or oil price rises, the tax payment or the duties are essentially lower per barrel.

So as we've seen in the second quarter versus the first quarter, we've had a rise in the price, which has led to a lower duty than what you would use as your rule of thumb.

So it's a rule of thumb, but it's also having to watch the delta and the oil price and it is tricky, it is tricky.

We had the problem always projecting TNK-BP.

Got you, thanks.

And then in terms of the settlement, Jason, there's four big components to the piece.

The first one is around Clean Water Act fines and penalties, which has the 15-year payment schedule starting 12 months from when the consent decree becomes final.

So if the consent decree were to become final in February next year, the first payment would be due 12 months from that date, so that will take you to February 2017.

So that's kind of how the Clean Water Act piece works.

The same thing is with the Natural Resource Damage Assessment, exactly the same breakdown.

It will be 12 months from the consent decree becoming final and that will then set the trend for future payments.

In terms of the state, it's a little bit more complicated, so I'll come back to that.

And then in terms of the various local government entities, as was announced in today's results, and was announced by the court yesterday, we did issue to the court yesterday, via a phone call, that we were happy and satisfied with the various releases we've been given by the vast majority of local municipalities.

Those payments will now start to progress over the next few weeks, and those payments will be made directly from the trust fund that was put in place.

In terms of the state settlements of $4.9 billion, structured slightly differently where $1 billion will flow when the consent decree becomes final again, that will flow from the trust fund and that will be paid to each individual state along an explicit formula.

And then there is a series of payments to take you out to, from memory, 2031 or 2032, over 18 years from where we are today, in terms of future payments, on a yearly basis that effectively becomes an annuity in terms of cash flowing into those five Gulf states around the state benefit claims.

Okay.

Thanks.

Neill Morton, Investec.

Just two questions left, please; I guess both for Brian.

Firstly, you mentioned about the removal of uncertainties, post the settlement, having changed your perspective of the gearing band.

How does it change your view of the [$33 billion] of cash on the balance sheet?

And then just secondly, in terms of tracking your cash costs.

In the dim and distant past, you used to flag a couple of lines in the income statement, the production expenses and the distribution admin expenses; can we still use those as reasonable proxies for your evolution of cash costs?

No, and I'll come back to why.

Because of so many moving parts in those costs, what we try -- so I'll take that one first.

We use a subset of what you -- one is, you'll still see those reported in the Annual Report and accounts.

I can't remember where they are, but it's way deep inside the document you'll find them reported.

There are so many moving parts and variable costs inside those.

We take a subset of those costs, which are the ones that we performance manage, and they're the ones that you see, where we see the $1.7 billion reduction.

That is actually consistent with what we set historically in previous -- when we set targets around cash cost reductions, it's the same subset of those.

But you will be able to track the high level numbers.

If they come down or up it will be coincidental with the programs we're doing.

It shouldn't be an indicator of whether we're driving costs in either direction, because of the variable nature of a big chunk of those costs.

And then in terms of uncertainties, our average costs of borrowing is tracking just above 2%.

But it's fair to say that you should assume that we would see our cash balances would trend downwards, over time, as this consent decree becomes final.

And the need to hold cash will be less of a concern, going forward, than it has been historically with the overhang of the potential requirement to post bonds against fines which will now lapse as a result of this settlement.

Do you think there's an optimum level for cash balances across the Company?

Yes, there is, and we run that within the financial frame, but we don't disclose what that number is.

But certainly since 2010, we now run with a cash buffer going forward, but it would be significantly below where the cash buffer is today.

Great.

Thank you.

All right.

Thank you, everybody.

That was the last question.

It's been a long call; thank you for your engagement and your patience.

I'll just hand over to Bob to make a few final remarks.

Right.

Well, thank you, everybody.

You have shown remarkable endurance, persistence and patience, which means you are kindred spirits with all of us here at BP.

I think the set of results, which came out this morning, were below expectations, but I think if you step back from it, it's really about the Libyan exploration write-offs, and we're probably about where most of you expected us to be.

We're not pessimistic about where we're going.

We think we have got programs going across the Company, in not only in the upstream where it's an obvious necessity, but the downstream.

And in our corporate simplifications and overhead reductions, we think this is going to serve us well as we go forward.

I think operability, we don't often get the chance to talk to you about our assets operating reliably and safely, consistently through the quarter, and this has been a remarkable quarter for us.

We're never going to be complacent about that.

But also, we didn't talk about safety, but our safety statistics this part quarter, at least, have been as good as they have ever been across the metrics that we measure.

So again, we're not going to be complacent on that as well.

Thank you all very much.

As we sit here I see the oil price is still got a [$52] in front of it for Brent and a [$47] in the US, so we're just going to continue to march on.

Thanks for your patience.