英國石油 (BP) 2016 Q1 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 first quarter 2016 results webcast and conference call.

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

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

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

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

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

These documents are available on our website.

Thank you.

And now over to Brian.

Thanks, Jess.

Welcome, everybody, and thank you for joining us.

It's been a challenging start to the year for our industry.

It is also a quarter in which we have seen considerable progress in our own business as we work to reposition the group.

We continue to see real momentum in resetting the cost base.

This is working to lower the point at which we expect to rebalance organic cash flows in 2017, and supports our continued commitment to sustaining the dividend as you have seen in this morning's release.

Our focus on costs together with sound operations, has also supported the solid underlying earnings and cash flow delivery you have seen today, despite the much weaker market conditions.

So I'll start today by looking at the business environment before covering our first-quarter numbers in detail.

I'll then update you on our medium-term financial frame where we continue to demonstrate both flexibility and resilience in our approach to resetting the Company.

I'll finish with a brief look at the first-quarter progress in our businesses before Jess and I take your questions.

Starting with an update on the macroeconomics where the market is responding to low oil prices and progressing broadly along the path we laid out to you earlier in the year; global oil demand looks set to increase strongly again this year, supported by low oil prices.

We expect demand growth to be around 1.4 million barrels per day this year, a little weaker than last year, but still comfortably above the historical average.

At the same time, global supply growth is likely to be flat to falling, with US tight oil supply falling in particular, only partially offset by increases in uranium production.

So our view hasn't changed materially over the past six to nine months.

We continue to expect the combination of robust demand and weak supply growth to move the market closer into balance by the end of this year.

This will still leave record high oil inventories to be worked down before a more settled position emerges.

Looking more specifically at the price environment so far this year, with continued oversupply, Brent crude oil fell to an average of $34 per barrel in the first quarter, compared to $44 per barrel in the fourth quarter and $54 per barrel a year ago.

Henry Hub gas prices continued to decline in the first quarter, with spot prices averaging just below $2 per million British thermal units.

The mild winter in the United States continued to suppress demand, while supply remained ample, including gas and storage at unseasonably high levels.

The global refining marker margin averaged $10.50 per barrel in the first quarter, the lowest since the third quarter of 2010, weighed down by weak diesel demand and high gasoline stocks in the United States.

Refining margins have recovered, averaging $12.70 so far in the second quarter.

This weaker environment is consistent with the assumptions we built into our plans for the first part of the year.

While it has had a significant impact on our results in the first quarter, this was also a period of strong operational delivery and visible progress on our cost and efficiency agenda.

Turning to the results for the group, BP's first quarter underlying replacement cost profit was $530 million, down 79% on the same period a year ago, and 170% higher than the fourth quarter of 2015.

Compared to a year ago, the result reflects lower upstream realizations, a weaker refining environment, and the absence of a one-off tax benefit arising from changes to UK supplementary taxation.

This was partly offset by lower cash costs across the group.

Compared to the previous quarter, the result reflects lower costs across the group and a higher contribution from supply and trading, partly offset by lower upstream realizations and a weaker refining environment.

First-quarter underlying operating cash flow, which excludes Gulf of Mexico oil spill payments, was $3 billion.

The first quarter dividend payable in the second quarter of 2016 remains unchanged at $0.10 per ordinary share.

In upstream, the underlying first quarter replacement cost loss before interest and tax of $750 million compares to the profits of $600 million a year ago and a loss of $730 million in the fourth quarter of 2015.

Compared to the first quarter of 2015, the result reflects significantly lower liquids and gas realizations, partly offset by lower costs from simplification and efficiency activities, lower rig cancellation costs, and lower DD&A.

Excluding Rosneft, first-quarter reported production versus a year ago was 5.2% higher.

After adjusting for entitlement and divestment impacts, underlying production decreased by 1.1%.

Compared to the fourth quarter, the result reflects lower realizations, largely offset by significantly lower costs, including lower expiration write-offs.

Looking ahead, we expect second-quarter 2016 reported production to be lower than the first quarter, reflecting PSA entitlement impacts and seasonal turnaround maintenance activity.

In the downstream, the first-quarter underlying replacement cost profit before interest and tax was $1.8 billion, compared with $2.2 billion a year ago and $1.2 billion in the fourth quarter of 2015.

The fuels business reported an underlying replacement cost profit before interest and tax of $1.3 billion in the first quarter, compared with $1.8 billion in the same quarter last year and $890 million in the fourth quarter of 2015.

Compared to a year ago, the result reflects a significantly weaker refining environment and a lower contribution from supply and trading compared with a very strong result in the same period last year, partly offset by lower costs from our simplification and efficiency programs, strong refinery operations, and a higher retail result supported by volume growth.

Compared to the fourth quarter, the result reflects a strong contribution from supply and trading compared with a small loss last quarter, lower costs, and strong refining operations, partly offset by a weaker refining environment and seasonally lower fuels marketing margin capture.

The lubricants business delivered an underlying replacement cost profit of $380 million in the first quarter, compared with $350 million in the same quarter last year, reflecting strong premium brand performance and margin growth despite adverse foreign exchange impacts.

The petrochemicals business reported an underlying replacement cost profit of $110 million compared to $20 million a year ago, reflecting improved operations, lower costs, and a slightly improved margin environment.

In the second quarter we expect a significantly higher level of turnaround activity, particularly in the United States, and some seasonal improvement in industry refining margins.

Turning to Rosneft, based on preliminary information, we have recognized around $70 million as our estimate of BP's share of Rosneft's underlying net income for the first quarter, compared to around $180 million a year ago and $235 million in the fourth quarter of 2015.

Our estimates of BP share of Rosneft's production for the first quarter is just over 1 million barrels of oil equivalent per day, similar to both a year ago and the fourth quarter.

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

On the 22 of April, the Rosneft board indicated an intention to increase its dividend payout to 35% of IFRS earnings.

At current exchange rates, this would imply dividend payable to BP of around $330 million after tax for 2015, payable in the third quarter of 2016.

The final decision regarding the payout will be taken at Rosneft's annual general shareholders meeting in June.

In other business and corporate, we reported a pretax underlying replacement cost charge of $180 million for the first quarter, $110 million lower than the same period a year ago.

This reflects lower corporate and functional costs and foreign exchange benefits.

We continue to expect the average underlying quarterly charge for the year to be around $300 million, although this may fluctuate between individual quarters.

The underlying tax rate in the first quarter was 18%, and reflects tax credits from the reported upstream loss offsetting tax charges elsewhere in the business together with a deferred tax benefit from the weaker US dollar.

This compares to a rate of 21% in the same period a year ago, after adjusting for the UK North Sea supplementary charge in 2015.

In the current environment, and with our existing portfolio of assets, we continue to expect the effective tax rate for the full year to be lower than the adjusted 2015 rate of 31%, which excludes the previously mentioned North Sea tax credit.

Turning to the Gulf of Mexico oil spill costs and provisions, earlier this month the court entered final judgment on the consent decree relating to the 2015 agreement to settle all federal and state claims arising from the Deepwater Horizon incident.

As a result, the consent decree and settlement agreement are now effective.

The total cumulative pretax charge for the incident to date is $56.4 billion, or $40.7 billion after tax.

The charge for the first quarter was $917 million, which includes: $593 million related to business economic loss claims not provided for, $201 million of costs relating to the settlement of certain civil claims outside of the 2012 class action settlement and other administration costs, and financing costs of $123 million.

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

We have, however, now agreed simplified and accelerated procedures for processing claims, which you see reflected in today's higher charge.

Of the $20 billion paid into the trust fund, $19.8 billion has now been paid out with the remainder allocated to amounts already provided for.

The pretax cash outflow on costs related to the oil spill for the first quarter was $1.1 billion, including $530 million relating to the 2012 criminal settlement with the United States Department of Justice.

We also expect a further $1.1 billion of payments in respect of the 2015 settlement, as well as further payments related to business economic loss claims and of the costs not yet provided for.

We will continue to update you on a quarterly basis, including any further developments with the Private Securities Litigation under MDL 2185.

Now looking at cash flow, this slide compares our sources and uses of cash in the first quarter of 2016.

Excluding oil spill-related outgoings, underlying cash flow for the quarter was $3 billion, including a working capital build of around $800 million.

Gulf of Mexico oil spill payments of $1.1 billion were offset against divestment proceeds, which also amounted to $1.1 billion in the first quarter.

Including oil spill payments, operating cash flow for the quarter was $1.9 billion, similar to a year ago.

Organic capital expenditure in the first quarter was $3.9 billion, compared to $4.4 billion a year ago.

Turning now to our financial frame and starting with some context, our financial framework is designed to grow long-term value for shareholders while maintaining the financial health and liquidity of the group.

This requires us to determine the right level of reinvestment, to continue to grow value while ensuring we distribute sustainable returns to shareholders.

We believe getting this right is strongly linked to making the right decisions about our portfolio.

At its simplest, we have prioritized value over volume and will continue to do so on an ongoing basis.

We look to divest assets which no longer fit with our strategy, and deepening assets which add the most value.

At the same time, we drive returns through disciplined investment into the best projects.

In the current environment all this still applies, but we have an added imperative to make very careful judgments about how we use our scarce capital.

We have to balance the pace of investment to capture maximum deflation, while ensuring we maintain safe operations and preserve future growth.

We also wish to retain flexibility to add to the portfolio at the lowest point of the cycle if the right opportunities present themselves.

So there's a lot of moving parts that we need to continue to manage while the environment remains unsettled.

We entered this down cycle with a strong balance sheet, and we have a strong portfolio with a resilient downstream and a new wave of material upstream project startups in sight.

We have also moved very quickly to reset the cost base of the Company for a lower price environment.

Consistent with many others, we anticipate a modestly more favorable oil price environment in 2017 than we see today, but believe we have the flexibility to withstand the range of outcomes.

If oil prices remain lower for longer than anticipated, there will inevitably be trade-offs that we need to take, but we will continue to be governed in these decisions by what we consider to be in the best long-term interests of shareholders.

Looking at the specifics of our financial frame, we continue to make strong progress on resetting both the capital and cash cost base of the group.

We now expect capital expenditure in relation to the current portfolio to be around $17 billion this year.

We see room to reduce this to between $15 billion and $17 billion per annum for 2017 in the event of a continued low oil price.

This compares to our guidance in February of 2017 to $19 billion per annum for the same period, while at that time 2016 spend was expected to be at the lower end of that range.

Today's guidance suggests the 30% to 40% drop in capital expenditure by 2017, compared to around $25 billion of spend at the peak in 2013 when Brent oil prices averaged $109 per barrel.

The reduction has come through, paring back expiration spend, prioritization of marginal activity, and the capture of accelerating deflation in the supply chain, as we time our investment decisions.

Significantly, it also reflects a strong drive towards capital efficiency in our development plans, which is allowing us to deliver the same activity for less spend.

In areas where we still see flexibility to optimize activity, we will judge very carefully the implication to the business, retaining the ability to increase activity if prices strengthen.

We will continue to realize deepening deflation, and balance the overall best use of funds to the prevailing oil price.

Our intention remains to stay very focused on both safety and our growth plans for the future.

We also continue to move quickly to lower controllable cash costs across the group.

The group's cash costs over the last four quarters were $4.6 billion lower than 2014.

This demonstrates the ongoing momentum behind our efforts to reduce costs, and put us about two-thirds of the way through to delivering the $7 billion of cash cost reductions by 2017 compared to 2014.

As we continue to lock in capital efficiencies and embed structural simplification, along with a more controlled organization, we expect a large part of the cost savings to be sustainable for the future.

Non-operating restriction charges are expected to approach $2.5 billion in total by the end of 2016, with around $1.9 billion incurred so far since the fourth quarter of 2014.

Of this, around $350 million was incurred in the first quarter.

Our principle aim is to reestablish a balance where operating cash flow covers capital expenditure and the dividend over time.

In this way, we look to ensure that levels of reinvestments and distributions are consistent with the long-term growth of our underlying business.

We have been working towards a goal of rebalancing by 2017 at the prevailing oil price, which back in October 2015 we pegged at $60 per barrel, consistent with the forward curve at that time.

As we steadily take more costs out, the Brent oil price, which we would expect to breakeven continues to move lower.

We now anticipate rebalancing organic sources and uses of cash by 2017 at oil prices in the range of $50 to $55 per barrel.

This currently defines the basis for our ongoing commitment to sustaining the dividend as the first priority within our financial framework.

Actual inflows and outflows will be subject to ongoing recalibration to the environment, including the judgments we make around levels of capital expenditure and any changes to the portfolio.

Once rebalancing is achieved, organic free cash flow is expected to start to grow at constant prices, supported by the stronger cash flows expected from our upstream project startups over the medium term.

This will in turn support distributions to shareholders.

With divestments having reached $10 billion over 2014 and 2015, we continue to expect $3 billion to $5 billion of divestments in 2016 and around $2 billion to $3 billion per annum thereafter, in line with historical norms.

The proceeds from these divestments provide additional flexibility to manage oil price volatility, and capacity to meet our Deepwater Horizon payment commitments in the United States.

Turning to gearing, at the end of the first quarter net debt was $30 billion, with gearing at 23.6%.

This includes the impact of the consent decree and settlement agreement the gulf states had on our balance sheet during 2015, and the scheduling of payments over an extended period.

As a reminder, during 2010 we lowered our gearing band from a historical range of 20% to 30% down to 10% to 20% to manage uncertainties, mainly in relation to the Deepwater Horizon incident.

Having finalized these agreements, we are reestablishing a 20% to 30% gearing band going forward.

Now turning briefly to the highlights of the quarter from our businesses.

Starting with the upstream, we have seen continued strong operational performance.

Plan reliability was 95% across our operator producing assets, and we saw strong drilling performance, particularly in the United States' lower 48 and Azerbaijan, delivering both cost and efficiency benefits.

The first quarter saw the startup of the In Salah Southern Fields major project in Algeria, and we also recently saw the startup of the Point Thomson project in Alaska.

We also have two projects in the commissioning stage, and two further projects continued to progress well for startup later in the year, with facilities work nearing completion.

For example, we saw the safe arrival of the new FPSO for Quad 204 in Norway ahead of its installation to the west of Shetland this summer, ready for startup around the end of the year.

Overall, we continue to have momentum on our upstream major projects portfolio as we look beyond this year.

Our 2017 startups are on track, and together with our six 2016 startups, we expect to put in place 500,000 oil equivalent barrels per day of new net BP capacity by the end of 2017 versus 2015.

For example, our Khazzan project facilities are now 69% complete, with 46 well pads completed and startup expected to be a little ahead of schedule.

Juniper, which will backfill production into our Trinidad LNG trains, is progressing well with over 55% facilities completion.

In Egypt, facilities for the Taurus Libra on West Nile Delta project are also on schedule and around 50% complete, while the top side modules for Claire Ridge in the North Sea are en route from South Korea, and are expected to arrive later this quarter.

Beyond these 2017 startups, the production facilities for our Shah Deniz Phase II project are ahead of plan at around 70% completion, with first gas scheduled for 2018.

All of this means we remain on track for the delivery of over 800,000 barrels per day of production from new major projects by 2020.

In February, our first exploration discovery of the year was announced on a Nooros East prospect in Egypt by the operator Eni, who have now tied it back for production.

Meanwhile, we have completed evaluation of the BP-operated Kepler 3 discovery drilled in late 2015, and are in the process of tying this well into our Na Kika platform with the aim of starting production later this year.

These are great examples of the opportunity for rapid monetization of near-field discoveries of what we call, infrastructure-led exploration.

The first quarter was a strong quarter for new access, including farm-ins and licenses awarded for new acreage in Norway and Newfoundland, Canada with an aggregate total of around 12,000 square kilometers.

In Oman we signed a major agreement to extend the Khazzan license to access a further 1,000 square kilometers, estimated to contain around 3.5 trillion cubic feet of gas.

Combined plateau production from Phases I and II is expected to total approximately 1.5 Bcf of gas a day, equivalent to around 40% of Oman's current total domestic gas production.

Additionally in the first quarter, the government of India announced a series of policy initiatives, including marketing and pricing freedom for natural gas produced from deep water discoveries, which we believe is a positive development and are evaluating for future projects.

We also signed two new agreements, one with QA Petroleum Corporation to enhance recovery of existing oil and gas resources and pursue future oil and gas exploration opportunities, and a production sharing agreement in China to develop shale gas resources.

In the downstream, the first quarter saw strong year-on-year underlying performance improvements, mitigating the impact of a weaker refining environment.

At the same time, our refinery saw a 4% increase in utilization, while we increased the amount of advantaged heavy crude processed by more than 20%.

And in petrochemicals, we are improving the cash breakeven of the business, making it more robust to a bottom of cycle environment.

Our marketing growth strategy continues to deliver results.

The global roll out of our ultimate fuels with active technology represents our biggest fuel launch in over a decade.

We also expanded our convenience retail partnerships in Germany and the Netherlands, and we became the world's first supplier for commercial jet biofuel using existing airport infrastructure.

In lubricants, we continued to see double-digit earnings growth supported by strong premium brand performance and growth market positions.

And simplification and efficiency has progressed across the downstream into 2016, keeping the business on track to deliver $2.5 billion of cost efficiencies by the end of 2017.

Taken together, this momentum in underlying performance improvement continues to support the increased resilience of the downstream business.

In summary, the environment is very challenging, but we are seeing the benefit of having moved quickly to respond.

We have considerable momentum around resetting our cost base.

This is driven by both the pace at which we are capturing deflation and our own simplification efforts.

You have seen more evidence of this across all our businesses in today's results.

We are steadily lowering the oil price at which we expect to balance organic sources and uses of cash by 2017, while retaining sufficient flexibility to make the right choices about our portfolio to sustain growth.

I believe we are making strong progress.

We are executing our projects safely and more efficiently, driving down costs and making careful judgments about the best use of scarce capital.

And all our decisions continue to be guided by our ultimate aim to grow sustainable free cash flow and distributions to shareholders over the long term.

On that note, thank you for listening.

And I'll now open up for questions.

(Operator Instructions)

Thank you to all of those waiting on the line.

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

Are you there, Irene?

Thank you, Jess.

I had three questions relating to CapEx, if I may, Brian.

The new budget for next year is $15 billion to $17 billion.

What proportion of the reduction versus this year's budget would you say is inflation?

Secondly, within the $15 billion to $17 billion, roughly how much would you say is maintenance versus, let's say, growth?

And then finally, in your comments regarding the financial framework, you referred to the effort to set the right level of reinvestment.

I wonder if you can clarify how the $15 billion to $17 billion fits in that?

In other words, how do we ensure that is the right level of reinvestment, perhaps in terms of reserve replacement or other?

Thank you.

Thanks, Irene.

And maybe if I just sort of start with where we came into this year.

As we thought about where capital would fall out in terms of the various projects that we pursue, we set you a range of $17 billion to $19 billion.

And that was in the middle of this effectively rebalancing the Company out to 2017.

It now transpires, as we've seen more deflation come through, more things we're doing around the ways in which we're working in terms of our own self help, we're now confident that actually the capital is coming at it somewhere around $17 billion.

So we've revised that guidance for this year.

The range for next year has really been set to say, actually if the oil price were to stay low at the levels that we see today, that we would have flexibility within the financial frame to move that capital lower.

That isn't something we would choose to do today in terms of the rebalancing at $50 to $55 a barrel.

So I think the basic assumption is that to the degree that we see oil prices staying low, there will be some more deflation come through.

But you should assume next year, that if all things being equal and we see the second half of this year, the firming up of the oil price from where we see today and a small recovery, quite a modest recovery.

So, we're not talking a major move from where we are, that in the range of $50 to $55 a barrel you would expect that our capital will come out somewhere between $15 billion to $17 billion.

But it probably would not be at the lower end of that range.

We would only move to the lower end of the range if we saw continued pressure on the oil price.

And that's on today's portfolio.

In terms of the maintenance versus growth spend, I think we've laid out for you all the various projects that we look at that drive growth in terms of 2016; significant growth in 2017, with the projects that come on in the second half of next year.

Typically, historically our maintenance CapEx will come back and confirm it, but just from memory from previous calls, typically it's around about 40% of the capital budget would be around maintenance versus growth.

Thank you.

And in terms of the, say, right level of reinvestment longer term, how do you think about setting that reinvestment?

If you look historically at both the sector and BP, typically we've reinvested anywhere from 70% to 80% of capital back into the business in terms of driving future growth.

So far, we haven't limited the growth that we laid out for you five quarters ago in terms of 2017, 2018, 2019.

So we feel it's the right level of reinvestment as we go through this transition with the oil price, but something around 70% to 80% is typical in terms of the sector.

Thank you very much.

Thanks, Irene.

We'll take a question now from the US.

Blake Fernandez of Howard Weil.

Thanks, Jess.

Couple of questions on production, if you don't mind.

If I recall, the previous guidance was for relatively flattish type of production in 2016.

It looks like 1Q is off to a pretty good start, so I'm just curious for one, do you think that flat profile is still the right way to look at it?

And then secondly, with 500,000 barrels a day of new production coming on through 2017, can you give us an update on what the portfolio decline looks like currently?

Yes.

So I think first, let's start by saying that of course the PSE impacts quarter on quarter.

If you look at 1Q this year versus 1Q last year, there is an uptick in terms of how the PSA works around the actual price itself.

But we are actually seeing strong performance out of both the North Sea, lower 48, and the Gulf of Mexico, in terms of first quarter production; offset a little bit by some issues around some declines in some more lower margin fields in places like Trinidad and North Africa.

So in the round, it looks strong 1Q versus 1Q, but a big chunk of that is coming through the PSE effects.

In terms of looking out into 2016, I think as Lamar laid out on the last call that we had, and Bob talked about, relative decline of the base has been relatively low because we've had a lot of capital focused on the higher return in field development work.

So actually this year it's really more closer -- historically we've said 2% to 3%.

It's more of the 2% range in terms of this year.

Perfect.

Thank you, Brian.

I'll leave it there.

We'll take the next question from Jason Gammel of Jefferies.

Yes.

Thank you, Jess.

Brian, I just wanted to come back to the capital cycle, and looking into 2017, guiding for the breakeven of $50 to $55, at the upper end of the CapEx range of 2017 and with a dividend of about 6.5%, that's implying cash from ops of roughly $23 billion.

Does that include the proceeds from divestitures, or is that what you expect from operations organically?

No.

Thanks, Jason.

Actually what we've done is, we've actually changed back in October of last year, we re-laid out the financial frame because now we have certainty around the vast majority of Macondo liabilities.

What we've done is effectively said, operating cash needs to cover CapEx and dividends, and disposal proceeds will be used in terms of Macondo liabilities.

So it does not rely on the disposal proceeds in terms of that rebalancing.

It is a basic, simple operating cash needs to cover dividend and CapEx, and to be clear, within the frame that we've laid out, it is total dividend.

It's not just the cash dividend.

Understood.

If I could just follow up, Brian, on the divestiture process, obviously not a massive target, but still in an oil price environment where we're at, how are you expecting to be able to deliver these divestitures?

Are you going to be more reliant upon midstream and downstream type of assets, or do you actually see a market for upstream assets that could achieve value that you would find acceptable?

Everything comes back to the basic principles of what we laid out for you back in 2011, in terms of value over volume, and to the degree that there are assets within our portfolio that we believe are better in the hands of others in terms of reinvestment versus those ones that we would like to maybe acquire.

So this is not just about disposals.

That we believe we can add value to them, we'll look at both sides of that equation.

In terms of the quantum of 3% to 5% for this year and 2% to 3% going forward, the 2% to 3% is the historical average.

But of course, as Bob has said on previous quarters, we include or exclude TNK-BP.

We've sold up to $75 billion, if you include TNK-BP, or $50 billion if you exclude it, over the last three or four years.

So it's therefore not surprising.

And they were at $100 a barrel, which is somewhat fortuitous given where we are in the cycle.

It's not surprising that actually now we're really into what is the non-strategic tale of the business.

And 2% to 3% feels right going forward.

The current suite of assets that we're looking at, and you'll see it from the various sales announcements that happened; they are more midstream.

They were certainly more predominantly downstream last year and the first quarter of this year, but midstream downstream.

We will still look to exit upstream assets where we believe that they are better in the hands of others, and equally potentially invest in upstream assets and the downstream going forward.

Thanks very much, Brian.

Moving now to Lydia Rainforth with Barclays.

Are you there, Lydia?

Thanks, Jess.

Two questions if I could, please.

The first one on the cost savings and the $4.6 billion number, the 2014 reissues -- incredibly impressive number.

Are you able to split for us kind of how much of that is upstream, how much of it is downstream, and how much is corporate?

And just kind of were there are areas where you were actually ahead of what your expectation would be, and if there's anywhere where it's actually still lagging behind that needs a bit more work?

And then the second question was coming back to the $50 to $55 per barrel breakeven in 2017, at that stage it looks like the financial framework is rebalanced.

But then if I look at the project startups that you do have, be it Khazzan, Shah Deniz, is it right to think of that oil price breakeven moving down beyond 2017?

Thanks.

That's a great question actually.

So the first question on cash costs, it's across the piece.

It's upstream, it's downstream, and it's corporate.

If I start with corporate, because that's the one that we laid out for you in 2013, and you'll see from the annual report and accounts that it's actually one of the things that we targeted in terms of the group performance score card.

We've seen a significant reduction.

So over 30% of costs coming out of those corporate activities.

Equally, we're seeing significant reductions in absolute costs in both the upstream and downstream.

And in terms of what Tufan is doing in the downstream, it's efficiency drive in terms of the margin of the barrel that he's generating.

It's both absolute cost reductions, but also getting more efficient about the way in which those operations are run.

And in the upstream, it's really about more efficient ways of working, activity optimization, organization start, size and staffing costs.

But it's also around agency staff and how are those being deployed inside the organization.

In the case of the upstream, it's something like, I think the peak was 30,000.

The intent is to get down to something around 20,000 by 2017 in terms of total staff; BP and agency staff.

So it's across the piece.

On the breakeven economics, there's lots of moving parts, hence why there's a range around that.

Of course it also depends on the Henry Hub gas price.

It depends on the refining margin.

It depends on what's happening in any different -- many parts of our business.

So I try to deter people from focusing on a specific point in time.

Oil price is the balancing point, because we have a lot of flexibility within the frame itself in terms of how we'll get things back into balance.

But all other things being equal, I think to the degree that the oil price were to be lower next year and with the new projects coming on and ramping up into 2018, and we've tried to lay out for you just what it looks like in terms of balance, in terms of surplus cash; that obviously alleviates any other pressures that we have around refining margins and other components of the financial frame.

Thank you very much.

Thanks, Lydia.

Turning now to Jon Rigby of UBS.

Thank you.

Can I ask three questions, actually?

The first is on the CapEx number and the visibility you're getting on cost deflation.

Presumably you're starting to talk to the markets around new sanctions.

So maybe, you're able to just talk a little bit about what the kind of feedback you're getting on some of those sort of larger sanctions that you may be coming to, that gives you the comfort around that cost deflation.

The second is just on the dividend and the oil price progression.

So you talked about looking to get cash into sort of cash neutrality with a full cash dividend.

Does that mean that you would expect to move to a full cash dividend, or you're expecting some sort of hybrid of some sort of anti-dilution buyback and continued scrip?

And then the last question, and this is with your background, Brian as well, is that there's a big beat in the downstream but there's clearly some significant moving parts on trading, both 4Q to 1Q and 1Q to 1Q.

And I'm very clear that the market has tended to give very little in terms of a multiple to trading businesses anyway, but with that lack of visibility, I'm somewhat concerned that you won't get very much credit for what looks like a very good number today.

So is it possible that you can give some more guidance around the moving parts, 4Q to 1Q, 1Q to 1Q, on that downstream figure?

Thanks.

I'll work backwards.

So in terms of the downstream result, it wasn't just about supply and trading.

That's the first point.

I think that's quite an important one.

In fact, if you actually look at half of that, probably just in the half that came from the supply and trading business, which had a stronger quarter than 4Q where we had a slight loss in 4Q; but didn't have as good a quarter as the first quarter of last year.

So I think it's just to put it into context, yes, it was a certainly above average quarter for supply and trading in the downstream.

But there was a lot of other things going on inside the downstream as well.

I think Tufan and his team reacted early to what they could see in terms of what was happening with refining margins and got after further cost efficiencies and also good reliability through the quarter.

So, if you think about the balance for downstream in the first quarter, I think half of it just in the half that came from supply and trading, but actually half of it came from lower costs and better operations of the kit.

So I think that's kind of important.

I think there is a component of our supply and trading result, Jon, which I think you're alluding to, which is actually that business has changed a huge amount in the last 5 to 10 years, where there's actually a base level of business inside there now that actually reduces the risk around the volatility of that going forward.

And maybe we'll try through this year maybe to illuminate that through future quarters, in terms of maybe just some of the activities of the physical nature of that business that actually has more of a margin component to it, like a fuels business rather than what you think of it as trading.

In terms of cash neutrality, yes, the intent as we laid out in October included the scrip.

Of course that gives us some flexibility.

There's no intent at this point to go back in terms of what we offer in the way of a scrip.

That's a matter for the Board and for our shareholders.

It's something our shareholders like.

We had a very big scrip uptake in the first quarter.

For 2015, the scrip uptake was about 9%, from memory.

For 1Q, it was just over 40%.

There's a big tranche of our shareholders like the scrip as an alternative.

So I don't think there's any intent at this point to withdraw that.

However, we do recognize that then dilutes our shareholders.

So that's why we say in terms of cash neutrality, we would look to want to offset that scrip at some point in the future.

And you've seen the buyback program we had in place prior to the drop in the oil price but that would be a matter for the Board going forward.

On CapEx and cost deflation, it's really across the piece.

Just talking to Bernard in terms of the activities that he can see and what's happening on each one of the projects.

Even with projects where we're in development and 80% of the design and the kit is built into the price already, there have still been opportunities to go back and renegotiate 20% of the final cost.

So it's really across the piece, and I'll save a little bit of powder for Bernard later this year.

I know Jess is talking about an upstream investor day at some point this year, ideally in the first half of the year.

I think Bernard and the team will be able to give you a lot more flavor around what we're seeing.

But it really is -- literally as we sat and had a review with Bernard and his team a few weeks back and we went through at least six or seven different projects where there were lots of components of examples, where $150 million was being taken out through 11 wells in one specific development that we were looking at, how $100 million of that has been booked already and $50 million more to follow.

But it's just across the piece, Jon.

Okay.

Thank you.

Thanks, Jon.

We'll take a question now from Rob West of Redburn.

Thanks very much.

I'll ask two relatively financialsy ones.

The first one is on the business economic loss payments.

Should we expect it to continue running at this quarter's $600 million run rate in the coming quarters for 2016?

And if it does, do we burn through the entire overhang of BEL payments by the end of the year?

My second question is on the commodity price assumptions that you're using to manage the business.

So clearly the breakevens have come down again today.

Should I be drawing any read across there for the long run $90 oil price assumptions going into the impairment test?

And when would you look again at those?

Thank you.

On the latter question, we don't use $90.

$90 is the long-term assumption.

So we use the forward curve for the next five years and then $90 kicks in.

We'll be looking at our long-term price assumptions this year.

So, actually most of our project economics today are done at $60 a barrel in terms of those options that are coming forward to our resource commitment committee today.

On the BEL assumptions, this is a quarter where we agreed with the PSC and the facility to simplify the claims to accelerate claims, to look towards the final completion termination of that facility on a faster time line than we were on.

That has led to lower administration costs, but of course a higher number of claims.

So we saw a very large number of claims go through this quarter, hence the $600 million.

We can't at this point actually, given what is left in the facility, provide a provision around future BEL claims, but we'll continue to update each quarter.

But maybe just anecdotally to help you, what is publicly available is that we're now over two-thirds of the way towards processing claims in that facility.

Of the 147,000 claims submitted, 99,000 have been finalized by the CSSP where 39,000 offers were made and 59,000 that were closed with no payments.

So that kind of gives you a flavor of what's happened so far.

But there are still 48,000 claims that progressed through that facility.

And it's impossible from the work that we've looked at and what we've seen, to come up with at this stage, a best estimate of what that provision looks like going forward; but we'll continue to update that each quarter.

Okay.

Thanks.

Over to Guy Baber from Simmons.

Thank you very much.

Selective acquisitions were highlighted as an objective, looking at the slide deck.

Where in the portfolio or in the market might there be opportunity to add to the portfolio here?

What's the key criteria on which you will screen for acquisitions?

And I know you are constantly looking at a lot of assets all the time.

How would you characterize the current M&A market as it stands right now?

The M&A market as it stands right now in the upstream is there's a lot of assets out there available.

I think one of the overarching principles, and it comes all the way back to October 2011, is this concept of making sure there's value and it's value accretive for our shareholders.

So we have looked across the market.

We've looked at various options around infill asset acquisition, around existing positions that we have, or strategic infill options for us.

I think the key test has to be that it's accretive for shareholders.

And to the degree things are dilutive, then really you question why you would be using your cash on that.

So we have done some small acquisitions.

We've done some -- last quarter we mentioned some in the lower 48 that we did around some of our existing positions in the San Juan Basin.

And we will continue to look at where we can see an asset acquisition where we believe we can add value.

Typically we may be the operator or deepening in those positions, or indeed actually looking at swap options.

But it's been pretty tough to actually find things which are value accretive in the current market and there are a lot of assets up for sale right now.

So we'll continue to look and see and actually, as I said last quarter, we did do some small acquisitions.

We've deepened in one or two positions where we're the operator, and we'll continue to figure those options going forward.

Thanks, Brian.

Then I had one follow up.

You highlighted the 95% reliability for your upstream operated assets, and the improvements you've made in the underlying upstream operations have been impressive and important to the profitability.

What steps are you taking?

How are you ensuring that, that progress doesn't begin to erode in an environment where you're materially cutting back on your spending levels, assuming you are cutting back some into the base spending, and where you're letting people go as well?

Is that a risk that you are focused on addressing or that you see?

That's a great question.

And the thing -- everything starts with no compromise on safety.

It's the overarching guiding principle that we've done for everything.

I've actually guides us through 2010 through the 10-point plan for what we laid out for you two years ago and actually what you're seeing through these results.

And the absolute correlation between reliability, all the way back to safety, is very clearly there and you can see it through the results.

And you'll hear Bernard talk about that, you'll hear Lamar talk about it, you'll hear Tufan talk about it.

Bob always lays it out in terms of everything we do.

It's the overarching piece.

It's the safe place that we go back to is safety being the absolute number one priority.

And of course that leads to good reliability of the kit.

And if you think about the number of turnarounds we went through in 2011; something like 48 turnarounds in 2011; 35 in 2012; something like 23, 24 in 2013.

We're back to a much more stable, steady state now in terms of those turnarounds.

But that's absolutely where the reliabilities come from in terms of the kit.

Thanks, Brian.

And back in the UK, Henry Tarr from Goldman Sachs.

Hi, and thanks for taking my question.

I wanted to go back to Irene's question on CapEx.

If oil prices did remain low and you considered activity reductions due to the environment, how would you split or prioritize between major project deferrals and lower spend on ongoing existing production?

And then if CapEx spend were to come lower, would you still expect that 2% or the lower part of the decline rate on the base production looking into 2017?

Thanks.

I think that gets tougher.

Actually, once you go out to 2017, you're probably back into 3% to 5% historical average in terms of the decline.

The 2% I talked about really in the context of 2016.

So I think it gets difficult once you get down to $15 billion and what we see today in today's portfolio, because at that point we started to look in terms of future growth out to 2020 and 2021; and it's important that we continue to reinvest into the future.

And that's really where at this point you would have questions around all components of the financial frame that you would need to look at.

Based on all the fundamentals of what we see around supply and demand today, I think that's unlikely.

But nevertheless if that's what transpires and we find ourselves in 2016 and the oil price is where it is today, then we'll have decisions to take around all components of the financial frame.

And I think Bob said in the last quarter, we're not going to drive the bus off a cliff on the basis of everything being fixed within the financial frame.

We would have to look at all components of that.

Okay.

That's great.

I just had one follow up on deflation and how you think about deflation generally, and how much is being driven by FX and is there a cyclical services cost reduction component in there, or do you see the bulk of the costs coming out now as secular?

I think there was some Forex benefits we saw last year.

The dollar has actually weakened against most currencies other than the UK pound, which is more a phenomenon of the various issues going on in the UK around Europe right now.

I think the dollar itself actually through the quarter weakened slightly versus other currencies.

We're not really seeing Forex come through.

And deflation is one of those strange -- I know Lamar's talked about this on previous calls, but deflation isn't something that arrives on your doorstep.

It's something you have to work out.

You have to work with the contractors on, you have to renegotiate rates, you have to look at your activity, you have to find more efficient ways of working.

And I think if you go back certainly from previous comments, we've said about two-thirds of the savings that we are seeing coming through in the upstream are from self help, and about one-third is from deflation.

That deflation is actually from renegotiating contracts.

Of course there is a component of it from the rig -- if you look at deepwater rigs, there's no question the rates have come down by 50% compared to where we were a couple of years ago.

And that, of course, feeds into the underlying cost base.

Okay.

That's great.

Thank you.

Thanks, Henry.

We'll take the next question from Oswald Clint of Sanford Bernstein.

Yes, hi.

Maybe just a question on US gas, please.

I think you've said previously about a $2 Henry Hub breakeven price.

Can you maybe just give us an update on that price point, please, Brian.

Thank you.

Oswald, I think that's probably a cash breakeven price, and we're probably maybe -- probably $2 is about right.

In terms of earnings, it's more like close to $3, $3.50 in terms of where our portfolio is today.

That's after the work that Dave Lawler and his team have done in terms of bringing the costs down quite significantly in terms of our activity in the lower 48.

But I think a breakeven earnings number would be closer to $3.50.

Cash breakeven would be much lower than that, which reflects the activity that we've been doing in the lower 48 over the last five quarters.

Okay.

Thank you.

Thanks, Oswald.

Aneek Haq of Exane.

Go ahead, Aneek.

Hi.

A very quick question on refining.

I think you've highlighted, Brian, as well, that you're expecting some heavy turnaround in Q2.

If I look back over the last at least couple of years, I think refining availability's been quite high.

I just wondered how we should think about that quarter on quarter in terms of refining availability in Q2?

I think we are seeing certainly some of the refiners out there cutting runs right now.

We are not doing that.

And I think it really comes back to where your refinery's position in terms of the barrel and the margins available to those refineries.

I think we're now down to about 10 operated refineries, last time I counted and looked.

Most of those refineries are well upgraded, have good margins available even through these downtimes.

So we haven't seen any run cuts of our own in our own system, but we are seeing run cuts across other refineries and other refiners certainly in the first quarter.

I think refining margins look pretty robust now as we've come in and seen -- 1Q 2016 was the lowest we've seen since 2010.

So it was actually quite a tough quarter, a lot of that driven by diesel and distillate demand.

We've now come through that and we're seeing margins recover already this quarter, up to about $12.70 quarter to date, and they are looking pretty robust as we come into the driving season.

But right now we are not looking at [run] cuts.

Thanks, Aneek.

And we'll take the next question from Anish Kapadia of TPH.

Hi.

Couple of questions, please.

First thing I was just wondering if you could give somewhat of an update on where you are with some of your KFID decisions, what's driving your thinking on things like Mad Dog, Hopkins, Tangguh, and [Atoll] for this year.

And then the second one, just thinking about acquisitions again.

Given your long-term planning assumptions of $80 a barrel real and $5 Henry Hub, and there's clearly opportunities rising in the current market, I was wondering would you consider cutting the dividend to do a large acquisition that you believe to be long-term value accretive to BP shareholders?

I'll come back to that.

On the FIDs, specifically now isn't the time to announce what we're doing around Mad Dog Phase II, but I'll be looking forward to the quarter where we can talk about the FID having been done.

But I would expect that will be sometime, notwithstanding where we are with partners towards the end of this year.

I think that's something Bob alluded to on the last call and we talked around 4Q results.

In terms of the Hopkins well, we are in appraisal of that well and looking at where we go with it next.

On the other developments, we had four FIDs last year.

The other potential FID this year, other than Mad Dog Phase II, will be around the Tangguh expansion that we've talked about before around Train 3.

That's something that we're looking at this year.

In terms of acquisitions and dividend and financial frame, I think everything comes back to the financial frame and how we balance all the various components of that frame up.

The dividend is just one component of the frame as is the capital, as is the cost base.

And it's an actually relatively small component in comparison.

I think the key is provided we can get things back into balance next year, which is what we would anticipate now; certainly as we've see the costs firm up from being close to $7 billion coming down to actually $7 billion, the resetting of where the capital frame is.

I think we have a lot of flexibility within the financial frame.

We have a lot of capacity in terms of cash on the balance sheet if we were to look at those.

But as I said earlier, there is nothing at this point that we see to be accretive for shareholders that we would look to pursue.

Great.

Thank you.

All right.

Thank you.

So we do have a question coming in on the web from Nikesh Patel of the Wesleyan Assurance Society.

If the market rebalances quickly above $60 a barrel, would you increase capital above $17 billion, or would you remain conservative?

I think we have flexibility as the price begins to firm, which we'd expect by the end of this year.

And then into next year we still -- even at the end of this year, assuming things start to rebalance in the second half of the year the way we've described, it will still take probably a year to work through the excess capacity.

So I wouldn't -- I mean, let's just assume it moves back to something around $60 a barrel and therefore we have surplus cash available.

Then there is no question there are places where we can ramp up activity relatively in short order in places like the lower 48 in terms of the drilling program, Oman Khazzan, Oman exploration, Iraq, Alaska.

There are places where we can look to relatively easily ramp up drill rigs that we have available in terms of activity.

But we're not going to try and get into boom and bust.

We have to go back to the basics of what are the long-term growth options that we see.

We have a number of significant projects coming on stream in the second half of 2017.

We have then a long list of projects that we'll be looking to FID and appraise in terms of 2018, 2019, and 2020.

But we wouldn't be looking to significantly ramp it up if we saw oil prices come back to $60.

It would really be around what we'd do at the periphery of the existing portfolio.

Thanks, Brian.

And we'll take a question now from Chris Copeland of Bank of America.

I know we're long, so I'm going to make it quick and probably quite boring, Brian.

If I may ask you to update us on your 2016 outlook on all of those rather pedestrian items like depreciation, production, maybe you can give us numbers on the Gulf of Mexico payment schedule, as well as your effective tax rate.

That would be greatly appreciated.

Thanks.

Okay, Chris.

So effective tax rate would be lower this year than what it was last year.

It has a lot of moving parts around the tax rate.

I mean, it's coming quite low this quarter.

I think it was below 20% of the effective tax rate for 1Q.

But I would expect it to be lower than last year, is really the only guidance we can give you.

In terms of production, we laid out for you already that we expect it to be broadly flat with 2015.

DD&A again broadly flat with 2015, although beyond that I would then expect to start to see as some of the projects come onstream in 2017 that there will be a slight uptick in DD&A.

But certainly for 2016, I'll expect it to be flat at around I think $15 billion or just slightly north of there.

OB&C charges we laid out for you, about $300 million a quarter.

It's quite low this quarter.

There's lots of moving parts again in that figure.

But I think most of it you should find, Chris, on the website on the presentation.

Okay, thank you.

Thanks, Chris.

Next question from Neill Morton of Investec.

Thank you.

Good afternoon.

Two questions, please.

You mentioned on previous calls, Brian, that you are in the process of renegotiating well services costs.

I just wondered what progress you've made by the end of the first quarter and whether those benefits were included in the $4.6 billion number you mentioned.

But then secondly on gearing, as maybe nitpicking, but back in February you talked about managing getting around the 20% level.

Now you've gone back to the old band.

What has changed?

Is it simply the court settlement, or has anything else changed in terms of the trajectory of oil prices, pace of disposals, et cetera?

Thank you.

In terms of well services, I mean, it's across the piece, but maybe at one particular location where we've completed the tender, we have 80% of the well services scope has already competitively bid with 20% still to be renegotiated.

And we've seen a 15% reduction in well services spend in that particular location.

That would be just one example, but there are many across the piece that Bernard and the team can lay out for you later this year.

In terms of the gearing, it was really, it was as you just alluded to, it was convenient to run a 10% to 20% strategy when we did because it wasn't only just the issues around Macondo.

It was also the oil price outlook where we've been pretty bearish since the middle of 2014 in particular where we expected a correction, not as big as we saw, but certainly a correction.

But now that we have the consent decree as final and it is now done in terms of the courts approving that, it seemed absolutely logical that we went back to the old band.

Actually we've got a lot of push from our investors to say why haven't you gone back to 20% to 30% band.

Because even at 30%, that still gives us a huge amount of flexibility, not that we have any intent of going anywhere near that this year.

But the idea that you're back in the 20% to 30% band made complete sense, given that now the vast majority of exposure around Macondo is not only taken care of in terms of that one legal settlement, which caught a huge amount of components of the Macondo liabilities, that created the uncertainty that moved us to the lower end of the range.

But it was also the certainty that we now had in place a plan to rebalance the portfolio going forward at this new lower oil price set.

And I think it resonates where the investors were feeling better.

Thanks.

Just a follow up on the costs, when you're signing new contracts, the price concessions you achieve, are they typically time-limited, or are the contracts linked to the oil price?

It depends on what the nature of the contract is.

Some of those contracts are linked obviously to oil price in terms of how you recover capital, and some are not.

Those benefits wouldn't typically go into the $7 billion target in 2017?

Just to be clear, because actually that's more on the capital side in terms of what you're asking about.

In terms of the costs, it will be across the piece.

So the cost, there are benefits coming from head count, activities, renegotiations of contracts, it's across the piece.

But the thing that you're alluding to around well service, a lot of that is capitalized.

Great.

Thank you.

Thanks, Neill.

Turning now to Lucas Herrmann of Deutsche.

Good afternoon, Brian.

Thanks for your time, and sorry about Saturday as well.

Three, if I might quickly.

First one, in terms of divestments, they are becoming increasingly small, it's increasingly difficult on our side to try and assess what the cash associated, or the income associated with the assets you're selling is.

In short, how should we think about the cash or the income that you're foregoing or the obligations you're taking on as you start to divest smaller assets, if there are indeed any?

Secondly, provision spend on restructuring, when do you actually expect it to end?

Is it 2016, predominantly going to see an end to it and in 2017 will it be relatively clean?

And thirdly, as we go through this period where a number of businesses are probably in tax loss, how much tax upside is there as profits start to recover and you find those profits are sheltered?

Okay.

Lucas, thank you for the comments about Saturday.

I'm sure most people are wondering what you're talking about, but that's very much appreciated.

In terms of divestments, there is some operating cash with them, but they're nothing like as accretive as they were historically if you think about where the oil price is.

And those midstream assets and some of those downstream assets that we've talked about, some operating cash is gone, but nothing like at the same level that we divested in that big first tranche of the $75 billion.

In terms of provisions, we have to each quarter look at what the carrying value is of all of the assets.

I presume you're alluding to the things around Macondo provisions that we've taken this quarter?

No, I'm really referring to restructuring.

I'm trying to think in 2017 how clean -- to what extent are we going to see the full benefit of the restructuring savings with operating level coming through.

Either they won't be offset by a further $1 billion or so of restructuring charges.

Sorry.

Probably second half of 2017 will be the first time you'll see a clean set of costs with both no more provisions.

Actually, I would expect the bulk of the provisions to be cleared out through this year.

However, there will be some potential cash that flows out with those provisions in the first half of 2017 as people leave the organization towards the back end of the year and cash payments go out in the first half of next year.

I would expect probably 2Q as being the earliest next year where you get a clean set of costs and cash numbers coming through.

So there's a hidden benefit if you like coming through each quarter because, of course, cash payments are going out each quarter affecting operating cash flow, and they all come back in the second half of 2017.

Yes.

And then in terms of taxes, yes, you're right.

Actually we've got a number of tax credits that we're carrying forward at the moment and the key is how we utilize those deferred tax credits.

But as we see recovery in the environment through the second half of this year, we're comfortable that those tax credits will get fully utilized going forward.

Okay.

Brian, thanks very much.

Thanks, Lucas.

A question now from Brendan Warn of BMO.

Thanks, Jess.

Brian, most of my questions have been answered, but just a follow up, and you probably answered it in saying all projects that start up in 2016 and 2017 are on track.

But any specific comments on Thunder Horse, if you could give us an update on those two projects please.

Yes, actually on track or ahead of schedule.

Thunder Horse is the south expansion, I presume you are talking about.

And water injection.

And on those right now we are -- let me just come back on south expansion.

Right now, the facility's progress is about nearly 50% complete, just below 50%.

And fabrication of critical path manifold and the slat is ahead of plan.

On the water injection, last time we looked at it, it was ahead of plan in terms of where we were.

But I would have to come back to you on the specifics of where we are in terms of development of that.

Thanks.

I'll leave it there, considering time.

Thank you.

Thanks, Brendan.

And we'll follow up with you on that.

Thomas Adolff of Credit Suisse.

Hi.

Thanks for taking my questions.

I've got two on project execution, please.

Firstly, if I take the IPA statistic, and they basically said the industry has destroyed value versus initial expectations on 75% of all projects completed in the last decade on a price-normalized basis.

They also said in total the value lost relative to project planning assumption has been around 35%.

So I wondered how BP's performance has been versus the initial budget over the past 10 years.

That's the first question.

The second question, again, on project execution, and I'm focusing here on current developments, I spent just over two weeks recently in Asia.

It was a lot of fun, but some of the feedback around shipyards didn't sound very encouraging versus the messaging we get from corporates generally for the industry.

So I wondered whether you see further risk on project delivery, especially those projects where some work is being done at some of the South Korean shipyards beyond Clair Ridge, assuming the information flow from the bottom to the top works as it should.

And also regarding Shah Deniz Phase II, I understand, and I might be wrong here, one of your partners has struggled to secure some funding related to the pipeline.

If that's the case, are you still comfortable everything is in line with expectations?

Thank you very much.

Okay.

Thomas, let me work my way through those three questions.

The first one, I would say simply that in the latter part of the last decade, our performance is significantly better than it was in the first part of the last decade, in terms of project execution.

And in terms of the stats that you quoted, we were probably as -- certainly on average as bad in terms of the way you've laid those stats out as anybody else in the sector.

We put in place in 2009 a centralized projects organization, which really I think -- we've talked about this on previous calls, really got into action over those subsequent years.

But particularly 2011 was the big year that project's organization really got after the 15 big projects we talked about, around the 10-point plan, the majority of which with the exception of one or two, for different reasons, were delivered on time and on budget.

And right now, I could lay out for you every one of our projects where we are in terms of specific execution versus everything else that we laid out.

I think one of the things that you will have heard Lamar talk about and Bernard in particular, since that project organization he oversaw, a lot of that was really around how you front end load the activity ahead of time in terms of planning and scheduling activity.

In terms of your specific question and in terms of where we are around the execution resisting projects, a lot better in the last five years than the previous five.

Then your next question, I'll come back to Shah Deniz Phase II, but it's probably the easiest one to take next.

Actually you were asking about Korean shipyards.

On the Korean shipyards, specifically the example you had in terms of Clair Ridge, last time we looked we've got all five modules are on their way from Korea en route to the west of Shetlands, and we have no issues around that right now.

But I do understand some of the constraints that are out there in terms of the shipyards and the activity.

Certainly what we could see about 18 months ago was there was a lot of stacking of activity in terms of getting all the projects through that were being lined up through some of those shipyards.

But we don't see any major problems right now around the existing projects.

In terms of Shah Deniz Phase II, that's progressing really well right now in terms of where we are.

If there are other partner issues, they are really questions that you should ask of those partners, not of ourselves.

So far Shah Deniz Phase II is progressing really well.

And to your exact question, we're about 71% completion versus 60%, which is what the plan would say.

Okay.

Thank you.

Just a quick follow up --

Come on, Thomas, you just had three questions.

What do you mean a follow up?

Okay.

Fair enough.

Fair enough.

No, go ahead, please, no, no, please no go ahead.

I understand that the industry is working to get better at executing projects, and front end loading is a key component to that, as you've highlighted.

I wondered, given that no one is taking any FIDs at the moment for various reasons, would it not be the perfect time to be really doing projects, because you get the best teams, you get access to all the best shipyards, et cetera, et cetera as opposed to waiting until everyone comes back and actually prices recover as well, I mean --

That's a really good question.

Actually in that respect, we're not trying to catch the low here in terms of rates for activity.

But there is no question, I think the pause, and Mad Dog Phase II is probably the best example of this.

The pause that we did around a number of projects, to go back and reengineer, rescope, reschedule, and recontract some of the activity has led to, yes, the project's moving sideways, but the economics and therefore the value to shareholders significantly being better.

But equally, we don't want to be sitting around waiting for the absolute low, low, low, low before we go FID.

It's a fair push to say that actually we're in that window right now.

Mad Dog Phase II is a good example of that.

Okay.

Thank you very much.

All right.

We'll have a question from Biraj Borkhataria of RBC.

Hi.

Thanks for taking my questions; I had a couple if I may.

One, going back to the lower 48, we've seen costs go down again Q on Q.

I was wondering if you could comment or talk about how that business is performing relative to the rest of your portfolio?

In terms of efficiency gains and productivity, is that faster or slower in terms of those gains?

And the second question would be on Oman.

There were some reports over the last month or so about a potential gas pipeline between Iran and Oman to be built.

I was wondering if you could talk about the potential implications for the Khazzan project, if there's any issues there.

Thanks.

I think the latter one is difficult to talk about until something actually gets announced, but there is no question that there is -- Oman Khazzan is progressing really well.

Development is going incredibly well.

We now expect to drill -- I think last time we reviewed this with Bernard, 85 fewer wells compared to the original scope that we had in place.

That would obviously be an opportunity, but that's not something I can comment on without having known the specifics of whether that actually were to go ahead in terms of a pipeline.

In terms of lower 48, first of all, again, Bob and Lamar and Bernard have talked about this historically.

This is more of a manufacturing business, so it's a little bit different to a offshore facility and a full offshore development.

That means you can take the rigs up much quicker, and you can also bring those rigs back down again.

There is no question, though, that bringing Dave Lawler in and his team and the reengineering of that business, the moving it off the main Westlake complex, the restructuring of the people inside that business, and the refocusing of the engineers back on the field developments has led to all of the improvements that you can see that we now publish each quarter in terms of the drilling costs coming down, the cost of production coming down.

And so difficult to replicate versus a say deepwater type alternative, but there is no question actually lower 48 creates for us a huge advantage in other options that we look like in our onshore developments, like Oman Khazzan, potentially maybe around China shale that we've announced recently.

But that is an important part as an asset base for the Company in terms of the technology that we develop inside there that we can deploy elsewhere in the world.

That's great, thanks.

Thanks, Biraj.

We have a late entry, and so last but certainly not least, from Jason Kenney of Santander.

Hi, everyone.

Thanks for hanging on for this question.

Just looking at some longer-term energy thematics, you just mentioned China shale there.

I wonder if you could give us some insight on the scale of the prize and the potential commitment from BP over the next few years, and is it going to be game-changing in the same way that US saw a turnaround over a decade in its gas markets any time soon?

And the second on global LNG, are you feeling the need to create demand for long-term LNG?

I'm just wondering what happens to fundamentals over the next 5 years, 10 years in global LNG.

Well, yes, that last question is quite an interesting one in terms of where does LNG go, given the number of projects that we see coming on in the back end of the decade.

Certainly over between now and 2020, there is a significant amount of LNG we can see coming on the market.

In terms of China, I can't tell you a lot I'm afraid, Jason, other than the fact it's 1,500 square kilometers, it's in the Sichuan Basin, and it's a great step forward in terms of our cooperation and working with CMPC, who will be the operator.

It ties back to an agreement we put in place back in October in London that Bob signed, and covers all sorts of other opportunities, even to fuel retailing in China, exploration of oil, and potentially LNG trading, which they are definitely interested in.

I think it's a -- it was a great landmark deal to get done in terms of progressing forward.

I think it's a little bit early at this point to say what opportunities will flow off the back of that.

In terms of LNG, we'll see the first cargoes of gas probably export out of the lower 48, out of North America certainly next year.

We'll see our own gas starts export in 2018.

I think the whole gas portfolio and the rebalance of gas globally, I think you'll continue to have the three zones around North America, the Far East, and Europe.

Whether there will be more connectivity as we see more LNG projects come on, I think you'll see more LNG pricing into the Far East non-oil related, which we've seen certainly in more recent times.

But there is no question there will be a lot of LNG available on the market.

We obviously can't create demand.

That will be something that will naturally be taken up probably in the Far East, and potentially in terms of power developments if you look at the lower 48 and the US.

And you're seeing a lot of industry activity being built off the lower 48 gas prices in North America, and I would not be surprised to see more of that trend, especially in terms of chemicals and manufacturing.

It's a big topic.

Big thematic.

Yes, Jason, we could go on for a long time.

But I think you are now the final question.

Good.

Thanks very much.

All right.

Thank you, everybody.

That is the end of our questions, and I'll just hand back to Brian to close the call.

Well, so first of all, thank you for your patience.

We've tried to cover all of the questions that you had today.

Just to summarize, safety, and we talked about this, safety, reliability remains the number one priority that we have within the Firm.

We've demonstrated through, I think, continued momentum on costs and capital and repositioning the Company to the lower oil prices that we see.

Dividend remains a key priority, and we've laid out for you now how we believe we can balance the books of $50 to $55 for next year; and we look forward to reengaging with you, certainly at some point this year around an upstream investor day.

And if not then, at our 2Q results where we'll have our segment heads and Bob available for the call.

But thank you for your patience and time.