英國石油 (BP) 2015 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 BPs first-quarter 2015 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 that 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.

And welcome to everyone dialing in.

I'll start with an overview of the environment for the quarter and then take you through the results, along with a reminder of how we are approaching our financial framework in response to lower oil prices.

I'll also update you on US legal matters and progress in our Upstream and Downstream businesses before taking questions at the end.

So starting with the environment.

In the first quarter of 2015 Brent crude oil fell to an average of just under $54 per barrel compared to an average of $77 per barrel in the fourth quarter and $108 per barrel in the same quarter last year.

This is the lowest quarterly average since the first quarter of 2009 and Brent has continued to average below $60 per barrel through April.

Oil supply remains buoyant, with a combination of OPEC increasing production and year-on-year production growth in the United States.

At the same time, OECD commercial stocks are at their highest level on record, with inventories in the United States at their highest levels since 1930.

Despite a significantly colder than normal February, Henry Hub prices in the first quarter were around 40% lower year on year, at an average of just under $3 per million British thermal units as a result of continued strong production growth.

By contrast the overall refining environment improved in the first quarter, impacted by planned and unplanned outages in the United States and Europe and improving demand.

The Upstream environment remains challenging.

And we continue to expect oil prices to remain weak in the short to medium term.

In our results, you're also seeing a number of quarter-specific impacts including costs associated with the actions we are taking to respond and other accounting and tax effects.

So I would characterize today's results as not only reflective of the new environment, but also of where we are in repositioning the Company.

Turning to the results for the group.

BPs first-quarter underlying replacement cost profit was $2.6 billion, down 20% on the same period a year ago and 15% higher than the fourth quarter of 2014.

Compared to a year ago the result reflects significantly lower Upstream realizations partly offset by increased Upstream production and improved downstream environment and performance, lower cash and non-cash costs across the group and a one-off tax benefit arising from the recently announced changes to UK supplementary taxation.

First-quarter operating cash flow was $1.9 billion including a build of $2.5 billion in underlying working capital.

The first-quarter dividend payable in the second quarter of 2015 remains unchanged at $0.10 per ordinary share.

In the Upstream, the underlying first-quarter replacement cost profit before interest and tax of $600 million compares with $4.4 billion a year ago and $2.2 billion in the fourth quarter of 2014.

Compared to the first quarter last year the result reflects significantly lower liquids and gas realizations, a lower gas marketing and trading results compared to a strong result a year ago and cash costs associated with the cancellation of two deepwater rigs in the Gulf of Mexico of just under $400 million, partly offset by higher production, lower exploration write-offs and lower cash costs resulting from ongoing simplification and efficiency activities.

Excluding Russia, first-quarter reports of production versus a year ago was 8.3% higher.

After adjusting for entitlement and poor failure impacts, underlying production increased by 3.7% mainly due to the ramp-up of major projects which started in 2014.

Compared to the fourth quarter the result reflects lower liquids and gas realizations, a lower gas market and trading results compared to a strong result in the fourth order and the cost associated with cancellation of the two deepwater rigs, partly offset by lower exploration write-offs and lower cash costs from simplification and efficiency.

Looking ahead we expect second-quarter reported production to be lower due to significant seasonal turnaround and maintenance activity, particularly in the Gulf of Mexico and PSA impacts.

Turning to Russia.

Rosneft are expected to report their final results in the coming weeks.

Based on preliminary information, we have recognized $183 million as our estimate of BPs share of Rosneft's underlying net income for the first quarter compared to $271 million a year ago and $470 million in the fourth quarter.

Our estimates of BPs share of Rosneft's production for the first quarter is just over 1 million barrels of oil equivalent per day, an increase of 2.1% compared with a year ago.

Further details will be made available by the management of Rosneft on their results conference call.

Earlier this year we made two BP nominations through election for the Rosneft main board.

These are Bob Dudley, an existing Rosneft board member, and Guillermo Quintero, an experienced member of BPs senior management team who is currently regional President for BP interests in South America.

Their nominations will be considered at the Rosneft annual general shareholders' meeting in June.

And finally, also subject to approval at Rosneft AGM, we expect to receive our next dividend from Rosneft in the third quarter of 2015.

In the Downstream, the first-quarter underlying replacement cost profit before interest and tax was $2.2 billion compared with $1 billion in the first quarter last year and $1.2 billion in the fourth quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $1.8 million compared with $700 million in the same quarter last year and $930 million in the fourth quarter of 2014.

Compared to a year ago this reflects a stronger overall refining environment despite weaker crude oil differentials in the United States, increased refining optimization and production and improved marketing performance, stronger oil supply and trading and the benefits of our simplification and efficiency programs resulting in lower costs.

Compared to the fourth quarter the result reflects an improved refining environment, strong supply and trading and reduced costs, partially offset by lower marketing margins.

The lubricants business delivered an underlying replacement cost profit of $350 million (sic - see Group Results for the First Quarter, "$345 million") in the first quarter compared with $310 million (sic - see Group Results for the First Quarter, $307 million") in the same quarter last year.

This reflects continued momentum in growth markets and improved efficiency resulting in lower costs, partially offset by adverse foreign exchange impacts.

The petrochemicals business reported an underlying replacement cost profit of $20 million (sic - see "Group Results for the First Quarter, "$17 million") in the first quarter versus a breakeven result (sic - see "Group Results in the First Quarter, "4 million") in the same period last year.

Looking forward to the second quarter, we expect refining margins to be similar to the first quarter and a significantly higher level of turnaround activity.

In other business and corporate, we reported a pretax underlying replacement cost charge of $290 million for the first quarter, a reduction of $200 million on the same period a year ago.

This reflects improved business performance and lower corporate and functional costs.

We continue to expect the average underlying quarterly charge for the year to be around $400 million, although this may fluctuate between individual quarters.

The first quarter tax charge includes a number of one-off tax benefits, the most significant of which is the reduction in the rate of the supplementary charge in the United Kingdom.

The opposite effect was reported in 2011 when the supplementary charge was increased.

In the near term we do now expect that there will be any cash flow impact from this change.

Excluding the one-off North Sea deferred tax benefit, the underlying effective tax rate for the first quarter was 21% compared to 33% a year ago.

This lower effective tax rate reflects changes in the mix of our profits and certain one-off items, partly offset by foreign exchange effects from a stronger US dollar.

We continue to expect the effective tax rate to be lower this year than 2014.

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

The total cumulative pretax charge for the Gulf of Mexico oil spill to date is $43.8 billion.

The charge for the first quarter was $330 million.

This reflects the ongoing costs of the Gulf Coast Restoration Organization and around $300 million related to business economic loss claims not provided for.

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 deadline for submission of all final claims is June 8 of this year.

Regarding the Clean Water Act, we continue to believe that our original provision of $3.5 billion represents a reliable estimate of the penalty in the event we are successful in our appeal of the Phase I gross negligence ruling, and we have maintained provision at this level.

The pretax cash outflow on costs related to the oil spill for the first quarter was $690 million.

This includes just under $600 million representing the third series of payments under the schedule agreed with the Department of Justice in 2012 relating to criminal fines and penalties.

A further payment of $530 million is due in 2016, $740 million in 2017 and a final payment of $1.2 billion in 2018.

Of the $20 billion paid into the trust fund, $15.7 billion has now being paid out, with the remaining $4.3 billion available for distribution.

Costs not provided for are being charged to the income statement as they arise each quarter.

Now, turning to progress on divestments and our objective to divest $10 billion of assets over the 2014 to 2015 period.

Agreed deals to date have reached $7.1 billion, and this total includes the sale of a package of assets on the Alaskan North Slope, the farm-down of 40% of our interest in the Oman-Khazzan project, the sale of our stake in the North Sea Central Area Transmission System, monetization of part of our Gulf of Mexico Paleogene interest, the sale of our Global Aviation Turbine Oils business and proceeds from our Toledo Refinery joint venture partner, Husky Energy, in place of capital commitments relating to the original divestment transaction.

We remain on track to reach our $10 billion objective this year.

Now, this slide compares our sources and uses of cash in the first quarter of 2014 and 2015.

Operating cash flow was $1.9 billion in the first quarter of 2015 compared to $8.2 billion a year ago.

Excluding oil spill-related outgoings, underlying cash flow was $2.5 billion.

This reflects the impact of lower oil prices on earnings as well as a build of $2.5 billion in working capital in the first quarter of 2015, which we expect to unwind as the year progresses.

The working capital build includes $1.4 billion relating to inventory optimization in high return contango market structures.

Our organic capital expenditure in the first quarter was $4.4 billion, and our full-year guidance remains around $20 billion.

We received divestment proceeds of $1.7 billion during the first quarter.

Turning to our financial framework.

In 2014 our financial framework reflected a position where operating cash flow exceeded capital expenditure and dividends as planned.

We ended the year with Gearing at 16.7%, and this was against a backdrop of the near $100 per barrel average oil price environment in 2014.

At the end of the first quarter, during which oil prices averaged just under $54 per barrel, net debt was $25.1 billion and Gearings stood at 18.4%.

Notwithstanding ongoing litigation in the United States, our intention remains to keep Gearing within the 10% to 20% band while uncertainties remain.

We're now responding to the reality of what we expect to be a sustained period of lower oil prices.

Along with a continued focus on delivering our businesses, we are working to complete our current $10 billion divestment program.

We have reset our capital frame to around $20 billion for 2015 compared to our original guidance of $24 billion to $26 billion, and we are actively resizing our cost base.

These interventions are designed to support our dividend in 2015 in the current price environment without compromising core investments for the future.

As explained in February, this requires an intense effort right across the Group.

We have booked a further $215 million restructuring charges in today's results, bringing the cumulative charge to $648 million to against the estimated $1 billion nonoperating charge we expect to see before the year end.

As well, the rig cancellation costs already noted illustrate the Upstream's focus on determining the right scope of activity in this new environment.

Over the medium term we expect to take greater advantage of sector deflation while continuing to reset our own controllable costs, with an objective of reestablishing a position within our financial framework where underlying operating cash covers capital expenditure and dividends.

As we have said before, our first priority within the financial framework is the dividend.

This reflects the commitment of our Board to maintaining a stable dividend, as you've seen today.

We can sustain this by successfully resetting our capital and cost base, and rebalancing sources and uses of cash in the prevailing oil price environment.

We will continue to review progress as we move through the year.

Turning to the ongoing Gulf of Mexico litigation in the United States.

The penalty phase of the MDL 2179 trial is now complete.

This was the third of three steps in the process of determining the amount of penalties under the Clean Water Act.

We do not know the timing for the District Court's ruling, but it could come at any time.

In the first phase the Court issued rulings which included the findings of gross negligence and willful misconduct by BP, and in the second phase the Court ruled that 3.1 9 billion barrels of oil were spilled into the Gulf as a result of the incident.

We have appealed both these rulings.

Phase II also found no gross negligence in our source control efforts.

As we've said before, we will pursue fair outcomes in all legal matters while protecting the best interest of our shareholders at all times.

Following a detailed review of internal controls and fraud prevention and detection measures at the Court-supervised settlement program, BP recently withdrew its appeal related to its motion to remove the claims administrator.

The review demonstrated improvements the settlement program have made and is continuing to make to the facilities administration, including the addition of scores of fraud investigators.

BP looks forward to working with all the parties to continue to improve the facilities operations.

We continue to compartmentalize these legal activities.

And BPs operational delivery teams remain fully focused on our core businesses.

Now, review milestones and progress in the businesses.

In the Upstream we remain focused on safe and reliable operations.

The selection, timing and execution of capital projects and driving cost efficiency into the business.

At the same time, there are a number of key milestones that are teams are working towards in 2015, and during the first quarter we have made good progress on a number of fronts.

In January we announced a new ownership and operating model with Chevron and Conoco Phillips to progress two significant BP Paleogene discoveries in the Deepwater Gulf of Mexico.

As we described to you in February, this deal will enable us to maximize synergies and support the development of a key part of our future in the Gulf of Mexico while also providing expanded exploration access.

Meanwhile, in Egypt we made another important gas discovery in the North Damietta offshore concession in the East Nile Delta.

Turning to projects.

The first of our planned start-ups for 2015, Kizomba Satellites Phase 2 in Angola, is expected to begin production very soon.

And we continue to make progress on three further start-ups planned for this year.

The Greater Plutonio Phase 3 development in Angola Block 18, the In Salah Southern Fields project in Algeria, and the Western Flank A project on the Australian Northwest shelf.

Also following start-up of steam operations last December, oil production began in March on the Sunrise Phase I project in Canada.

Total production is expected to ramp up to full capacity of 60,000 barrels per day gross around the end of 2016.

Looking forward to future developments, in March we signed final agreements for the development of the West Nile Delta projects, which will develop around 5 trillion cubic feet of gas resources in total.

Along with our significant investments in Oman-Khazzan and the Shaktonese Phase 2, West Nile Delta will contribute to the increasing share of gas production in our Upstream portfolio in the future.

In our operations we have maintained strong plant reliability at 94% across our operated assets in the first quarter.

We're planning 15 turnarounds this year compared to the relatively low number of 8 in 2014.

We began our 2015 turnaround program in April, and we expect to commence seven turnarounds in the second quarter, including Thunder Horse and Na Kika in the Gulf of Mexico.

We also continue to implement our plans to improve plant reliability in the North Sea with specific plans for each of our operated assets.

For example, we've already improved reliability on the [four nave] and gas compression system, and we are currently focused on our sand and produce water managing plans for ETAP.

Finally, but importantly, we are maintaining a clear disciplined on capital and cost management.

As you are aware, we have canceled drilling rig contracts in the Gulf of Mexico.

But beyond this we have deferred discretionary activity such as the restart of drilling on the Magness platform and made progress in engineering standardization across our projects and operations, all of which are delivering material savings.

And across our portfolio we are reducing headcount as we continue to simplify our business.

In the Downstream, we continue our strong focus on process and personal safety performance.

In addition, as outlined in February, our strategic priorities are to build an advantaged manufacturing portfolio to selectively invest in high return differentiated marketing businesses and to deliver our efficiency and simplification programs to improve our resilience to volatility and bottom-of-cycle conditions.

In petrochemicals we started up on new PTA plants in Zhuhai, China which has a capacity of 1 million tons per annum.

With this plant's advanced technology, we expect to reduce costs to help us become more resilient to bottom-of-cycle conditions.

In lubricants our focus on growth markets and premium brands continues to deliver like-for-like profit growth.

In retail we continue to see volume momentum in our growth markets.

We continue to actively manage our portfolio.

In the quarter we announced the sale of our bitumen business in Australia and completed a sale of our interest in UTA, a European fuel cards business.

And we're beginning to see benefits from the implementation of our simplification and efficiency programs as we streamline our businesses.

We have significantly consolidated the number of our reporting units and are aligning our head office and functional supports to capture the associated efficiencies.

So to summarize.

We're in the midst of a major transition as we work to reset the Company.

We remain confident that this is the prudent and right thing to do in the current market conditions.

Looking at today's results you can see the benefit of our integrated business.

We believe we benefit from having repositioned our portfolio to drive value over volume with right-sizing of the cost base already well underway.

Our near-term priorities remain those we set out in February.

Delivery the continued safe, reliable and efficient execution in our businesses; divestments, completing our current $10 billion divestment program; discipline on capital and cost, the resetting of our capital budget and right-sizing our cost base; and most importantly sustaining the dividend, which makes us keenly aware of the need to rebalance our sources and uses of cash for a lower oil price environment.

Longer term the roadmap is one of operating off a reset base.

We will realize the potential of our portfolio as we start up the next wave of Upstream major projects and look to improve returns in our Downstream business while maintaining strong cost and capital discipline.

Our focus throughout will remain firmly on value for shareholders.

Thank you for listening.

We are now ready to take your questions.

(Operator Instructions)

Welcome everybody.

We'll take the first question from Alastair Syme of Citi.

Good afternoon, everybody.

Brian, could I just ask you put provide a wee bit more color on how the sort of the provisions map into cost-cutting?

How will we be able to measure the outcome of this as it improved reliability, or will we see a reduction in cash costs, and can you give us some attempt to quantify where at in that process?

Thanks Alistair.

It's a good question.

And we're not going to quantify in dollar terms, but you should assume that if we've set aside $1 billion of restructuring, that's mostly around people.

And therefore you'd expect to get a minimum at least that amount of cost coming out of the system.

It'll actually a multiple of that.

You've seen of that original $1 billion that we laid out in December of last year, around the same time as the Upstream Investor Day, that so far we've booked about $615 million of those restructuring costs.

If you look at the headcount, this is something we talked about 18 months ago, two years ago as part of repositioning the Company.

Given the big wave of disposals that we had and looking to try to get our corporate and functional costs back in line with the new portfolio, and having an embedded lot of our safety and operational risk into the business lines.

So it's sort of a journey that we've been on now for close to two years.

We're starting to see the benefits of that in lower costs across both of the big major businesses, and in particular across corporate and functions.

So we haven't quantified an absolute number, but maybe just sort of anecdotally to help you with that, if you look at the number of people inside the Company for the annual report and account at the end of 2012 to the end of 2014, if you sort of cut through and take out the retail staff and the sort of biofuels farming agricultural staff, it's about a 3,500 reduction in people.

Now, some of that comes with the disposals.

But if you look at 1Q we've seen a further reduction of about 800 in the first quarter.

So we are actually now starting to see the benefits of lower costs come through already, with this now sort of trend over the last three quarters.

And we would anticipate to see more of that.

It's quite a painful process that we're going through.

And we just need to move through that and treat people fairly and equitably as we go through that process.

But you'd expect to see more of this come through in the results as we unveil the results for the rest of this year.

And you think we would see most of this show up in the Upstream business unit or would it be at the corporate level?

No, it's across the whole piece.

You're seeing it in the Downstream, you're seeing in the Upstream, we're seeing it in the corporate and functions that sits above the businesses, and we're seeing it in the functions that are embedded inside the businesses.

So it's right across the operation.

Thank you very much, Brian.

Okay.

Next question from Lydia Rainforth of Barcap.

Thanks, Jess.

And I just come back to Alatair's questions around the cost side.

Are you actually seeing a change in the way that BP is working, operationally so, when you talked about the number of people being reduced, which (inaudible) a difficult process.

But is that then leading to a change in the way that BP is actually doing things, which is then also helping the cost side?

And then just very quickly, at the Upstream Day in December, the indication at that time was about 20% of Upstream costs would come up for renewal in terms of third-party procurement side over 2015.

Are you able to give an indication of whether you are achieving the savings that you thought you would be in third-party procurements at this stage?

And then just a very quick one at the end.

I think that previously the indication was that you would give lower 48 disclosure separately.

I was just wondering where we are on that.

'Okay, Lydia.

Thank you.

On the latter point, I'll do that quickly.

You will, if you go searching on the Internet, I think you'll find on the one BP page there is now data that we released today around lower 48 around costs and volumes and structures inside lower 48.

So you will actually get line-of-sight on that.

You'll find that on the website.

So that's our first run.

I think it's got a couple of quarters, or one quarter's with of data.

And will look to update that as we go forward.

In terms of the first part of your question, it's coming through in terms of -- I think Bob talked about this two years ago.

But the 60 simplification projects that we laid in place, we are now starting to see the benefits of those.

Some of that -- and it different depending on where you are.

In the Downstream it's about de-layering the organization, the two (inaudible) has gone through and getting more of the operation closer to the day-to-day operations.

In the Upstream I'll talk about some of the things that we're seeing now in terms of standardization engineering [design] and some Company-wide reviews.

So anecdotally we've talked about the North Sea before.

But as an example, we've seen 400 staff and 100 contractors leave in the North Sea.

We've seen 380 onshore contractors that Bernard has talked about where we've got a renegotiated day rate.

In Trinidad we're seeing a 10% headcount reduction.

In Angola we're seeing a 30% ex-pat reduction.

What we're seeing, a number of changes across the piece.

In terms of -- what Lamar laid out for you in December, anecdotally where we've got to so far, and it's really as we progress through this year we'll see more and more come through, but some examples.

I spoke to Lamar before I came in today just to sort of get a sense where he's on the journey at the moment.

But we're seeing 20% CapEx savings in certain subsea production systems, 30% CapEx savings in certain control systems, 30% savings in subsea engineering CapEx, and in some specific projects a 30% reduction in the major project define estimates.

So it's across the piece.

It's everything, and it's actually sort of going back to nuts and bolts.

And you may have heard Bernard Looney talk about this in some of the investor sessions that we've been having, talking about how we need to get back to the basics of how we're designing some of the kits that we're operating today and actually getting a lot simpler about how we do that.

So there are no sort of single silver bullets.

It's kind of literally across the whole piece.

We're looking at everything in terms of how we get everything back into rebalancing the books going forward.

That's usually helpful.

Thank you.

Turning now to Jason Kennedy of Santander.

Thanks for taking the question.

So I was just looking for a bit of further color on perhaps second quarter LNG lag effects and if there's anything we should be anticipating there?

And also US Upstream, which I know was loss-making in the first quarter, and how that might play through the year?

And then maybe a more broad question.

I'm just wondering what your view is of the very wide range of consensus estimates for the quarter, which I think was almost as large as the actual result?

And presently this must be a very wide range for 2015 earnings.

And I'm wondering how you can better guide us to probably focus on a more -- a close number?

It's interesting how your trading statements, or your Monday trading statements on a week-to-week basis, have moved.

But it seems very difficult to kind of get more on the operational side quarter to quarter.

And maybe we're not playing quite as fast as you are at this game.

Yes, Jason.

I'll take that last point first.

I actually empathize.

I empathize with you at a time when even when we live through the quarters where it was $100 a barrel relatively stable quarter by quarter, it was pretty tough to predict results.

Frankly, this is the first quarter where we've seen the full effect of the drop in oil prices down to an average of $54 a barrel.

That's a lot of moving parts.

And for this quarter you also have the tax affects that came through in the first quarter, particularly around the North Sea, but of the one-off effects across the piece.

So I think that made it a particularly different quarter from a consensus perspective.

Hopefully now as you see the oil price stabilize around the sort of levels that we are today, and I think it's averaged about $57 so far in the second quarter versus $54 in the first quarter.

Refining margins are slightly up so far 2Q to date versus 1Q.

Henry Hub gas prices off a little bit.

So hopefully as we get more stable pricing it may become, that consensus range will start narrow back into a sort of zone that's more acceptable, whatever that means.

But I think it's [of] that perspective.

So I totally emphasize where you're coming from.

Jason, if I could just add, we have put a new rule of thumb on our website.

And with oil prices, if they stay a little more stable, then you should find that that rule of thumb works a bit better than it's done in the quarter where we've had such a very big drop in oil price in one quarter.

Okay.

On the first two.

So when LNG leg prices, Jason, all I can give you is what I can see on the forward curve where you've got MBP going out about $7.20 out to the back end of the year.

Henry Hub out at $2.80 and Brent crude parity around $11.60 in terms of 4Q.

Other than that I probably can't give you a lot of detail on LNG, but maybe we'll come back to you on any specifics on that outside of the call.

In terms of the US Upstream, it was loss-making for the quarter.

And of course, the rig cancellations, the Gulf of Mexico was loss-making for the quarter as well.

And is that a turn that's going to continue into the second quarter?

I think that's a function of what the oil price will do.

And I don't like to sort of get into that particular discussion.

But you'll start to see across the piece the benefits of what we're doing in terms of restructuring the organization and the Company.

But we'll measure this quarter by quarter.

Okay thanks.

Over to the US now, and Blake Fernandez of Howard Weil.

Yes, Jess.

Thanks.

Good afternoon, folks.

The production was fairly robust in the quarter, well above what we would have expected.

And I was hoping you could maybe frame up the impact from production sharing contracts in the quarter?

Yes.

Thanks, Blake.

I don't have the specific on the PSCs to hand -- PSA's to hand, we'll come back to that.

But I think what you're seeing in the production numbers is a good uptick in reliability, particularly out of the North Sea.

We've seen strong reliability across the piece.

But if I look just at the North Sea that we've talked about previously about getting reliability back, it was running at about 6% higher than 2014 in the first quarter.

And that's certainly a big part of seeing that production growth that we've got -- seeing come through in the first quarter.

PSA impacts will come back to you on.

Okay.

Thanks, Brian.

The second question for you, divestitures.

Just looking at the sources and uses slide in the quarter and then Gearing moving up a bit.

It just seems like it's likely that you're going to have to re-up the divestiture program.

You're already 70% through that $10 billion.

Any sense of when we may hear a new target, or if you're thinking that that is a likelihood, that we could increase that program?

No, not at this point.

I think we laid that program out back in 2013 for 2014 and 2015.

We're on track to deliver the $10 billion.

Beyond that date we'll get back into a typical churn of around $2 billion to $3 billion per year, and we'll review that at the middle of this year.

In terms of rebalancing source and use of cash, that is really going to come back through what we do around the efficiencies that we're driving into the organization and looking to rebalance the operating cash flows against the capital program going forward.

The key here is that as we do that, not to have major impacts on the long-term growth profile of the Company.

So I think everything we're doing at the moment is good for all seasons.

Some FIDs may move sideways.

Mad Dog Phase 2 is one that the Lamar's talked about on a number of occasions.

But that will be a better project as a result.

If you look at what's happening with rig rates now where we're seeing 40% to 50% reductions in rig rates.

So I think it's premature at this point to suggest [there's] a bigger program.

And remember, we sold $38 billion as part of the old program, plus a significant amount of cash that was released out of the TNK transaction in addition to that.

So our focus really now is on how we grow the Company from here with a new portfolio that we've built over the last three years.

And that's the sort of real focus here now.

We're not really in the sale mode.

Fair enough.

Thank you very much.

We'll take our next question now from Thomas Adolff of Credit Suisse.

Thanks for taking my questions.

Two, please.

One on the higher level of maintenance in 2015 versus last year.

Is this a function of, let's do it this year when the oil price is low and have better up time when the oil price recovers?

And also on the refining side, where exactly will maintenance be focused in the second quarter?

The other question I had was more on exploration, and I guess asset deals.

You never really quantified the cut to your exploration budget in 2015.

But looking at your exploration expense this quarter, I think I can get a feel for it.

But I guess adding resources inorganically, you talked about the [bp-to-ass] spread still being too wide.

I wondered whether you can comment where we are today?

And more specifically, if you were to add resources strategically, would you be looking to strengthen your existing hubs, or stuff you know pretty well, deepwater, et cetera?

And are you generally comfortable with the supply options you have in LNG?

Thank you.

Thanks, Thomas.

That's a lot of questions.

So the first one on turnarounds.

If you recall 2011, 2012, 2013 we had major turnarounds across the piece.

And just from memory, I think we ran at something like 45 to 48 turnarounds in 2011, 30 to 35 turnarounds in 2012, around 20 in 2013.

And in 2014 in the Upstream it was relatively low year of around eight turnarounds.

You also have to remember over that same period of time we've sold a number of assets and exited a number of countries and facilities and installations.

I think what you are seeing for this year, around mid-teens, 15 turnarounds this year, will be more typical going forward.

And I think we're now back into a more normal rhythm of turnarounds across the Upstream portfolio.

So I think this year's probably more of a typical year going forward compared to the big heavy turnarounds we went through post-2010.

So that's for the Upstream.

In terms of the Downstream, it will be a similar series of turnarounds as we went through in 2014.

So there's nothing particularly peculiar about that in terms of location.

So it will be pretty similar to previously.

In terms of exploration appraisal, I think as Lamar said at the 4Q results, or Bob described at the 4Q results, we have cut the expiration program quite significantly through 2015 as part of the rebalancing of capital down to $20 billion.

You have to remember that's off the back of two years of about 12 major discoveries that we had over 2013 and 2014.

So I think a big part of what we do now is consolidating what those discoveries look like in terms of what choices we make going forward.

And so far this year I think the plan was to drill out nine wells where we've already announced two discoveries and we have two under evaluation of the five that have already been completed to date.

Does that answer your question, Thomas, or did I miss anything?

Anything on the asset deals?

I mean, anything interesting?

(Multiple speakers)

On the purchase or sale side?

Purchase.

I think we'll see where the oil price settles for this year.

But I do believe, and I think Bob said at CERA this last week, that we will begin to see some potential financial stress in the markets in terms of potential opportunities for us.

And Lamar is working his way through potential options of what portfolio might like.

But I would think typically you look at things where we can deepen.

We're certainly not looking at [corporate] point acquisitions of this point.

It's more in the deepening in existing asset position that we have.

And you're comfortable funding this with cash or paper?

That is something I absolutely would not reveal at the moment on the call.

You wouldn't expect me too, either.

Thank you.

Next question from Anish Kapadia of TPH.

Good afternoon.

I had a couple of questions as well.

The first one was surrounding the US gas production, a big part of your overall production portfolio.

So I was just wondering, if you see Henry Hub pricing stay around the current levels, wondering what impact you see that having on your CapEx in the US?

I think you guided to about $1 billion to $1.4 billion on the lower 48.

And also the kind of the long-term impacts, the impact over the next couple years on production?

The second question was just on the tax side of things.

I was wondering if you could give some update on the underlying tax rate that you'd expect for the remainder of the year?

Excluding the UK impact, you still had a pretty low tax rate of 21%.

I think there was a mention of some one-off items in there.

So just wondering on a kind of normalized basis at current oil prices going forward, what kind of tax rate would you expect?

Thank you.

Okay.

Let me take that -- actually, no.

Let's take the gas question.

If you're thinking lower 48, we haven't talked about that.

I think we've learnt a huge amount since David Lawler was brought in and Lamar moved the business more arms' length and off the Houston campus.

We've now gone through a fairly major restructuring of that business.

And so therefore we are seeing the benefits of the way in which David's approached, effectively making that business competitive with the typical independents in the lower 48.

We have a specific financial framework around it with a specific CapEx allocated to it and an opportunity for them to reinvest in various options.

So I think it's still early days.

We started to release some information that you can see on the website.

We've had about 700 people leave the organization.

So we've seen the cost come down.

We're currently operating about nine rigs, one in Wamsutter, one in San Juan, four in Anadarko, one in Haynesville and two in Woodford.

So I think we'll continue to pursue opportunities.

Our cash breakeven is almost certainly coming down as we lower our costs in that business.

But it's really about how we make that competitive.

And I think as we've said before, there'll be more to follow on that as we progress through this year.

On the underlying tax rate, we've tried to -- the guides we've given you is that we're below last year's.

Of course as we now move around the mix of earnings, it's very hard to predict what the number will be for this year, other than it's certainly going to be lower than what the full-year effective tax rate was for last year.

We've given you the figure for 1Q.

I would expect, and some think around 30% is probably where the underlying effective tax rate will be this year.

But it's way too soon to sort of really give you guidance around that.

But as I look at the numbers now, depending on the sources of where the earnings come from across the various different geographies, something around 30% is probably a reasonable number to use for planning basis.

We'll give you more guidance as the year progresses.

So I wouldn't take that as a guidance, other than it's for your sort of -- it's sort of basic calculations, it seems like a reasonable sort of assumption going forward for this year.

Sure, that's helpful.

Just a quick follow-up on the first question.

In terms of your, the CapEx numbers, you point out the investment there.

I think things have kind of changed since then, of $1 billion to $1.4 billion for the lower 48.

Where do you see that actually shaking out now in 2015 with the CapEx cuts?

I think that number is still a good number.

It's around $1 billion.

We can come back to you on the specifics on that, but I would guess is just north of $1 billion.

So it'll would be in that range of $1 billion to $1.4 billion that we've talked about historically.

Great.

Thank you.

Turning now to Jon Rigby of UBS.

Thanks, Jess.

Hi, Brian.

Couple questions, please.

The first is on the dividend.

I noticed the last two quarters the script take-up has been very low.

Is that something that's, A, have you have any observations on that?

And secondly, does that impact, or what is the flex in your thinking around your financial framework with that lower take-up and as it relates to your Gearing, et cetera?

Secondly, just on Rosneft.

If you don't get a second director appointed on the board, as I think you mentioned you are putting one forward, will that prompt you to change your accounting for Rosneft within the BP Group going forward?

Thanks.

Okay.

On the dividends, while we don't target a script take-up it was something that we -- actually from memory, I think we introduced it the quarter, it was around the fourth quarter results of 2009, from memory, the script dividend was introduced.

And it was based on dialogue with shareholders, it was something the shareholders were keen on.

So we've seen quite a trend now.

And from my memory, I can recall we've had anything up to 45% take-up on the script historically.

I think the last couple of quarters have been relatively low, around 5%, 6%.

But we don't target it, Jon.

It is what it is.

Our shareholders have the choice as to whether they wish to take script or cash.

And we're don't attempt to incentivize them either way.

So it is what it is.

And it's sort of more of a backward-looking measure that we look at.

It's not something we try and target.

But you're right, it gives you flexibility or inflexibility around the financial frame.

But frankly, we don't really see that as being major driver, what we need to do in terms of rebalancing source and use of cash, which is the sort of number one priority at the moment.

You wouldn't feel the financial framework was jeopardized if take-up continued to be quite low?

No.

It's in the overall scheme of things, no.

Is de minimus in that respect.

In terms of Rosneft, we talked about this before, but there are five criteria that we look at around the equity accounting of Rosneft.

So board seat is -- having a board seat and having influence on that board is important.

We get that through Bob's attendance on the board, membership of that board.

The second board seat won't make a difference in terms of equity accounting at this point.

But we fully expect to get -- I think there are 14 nominations for nine seats, or 13 nominations for nine seats.

We put two forward and we'll find out more in June.

Okay.

Thanks.

Next question from Irene Himona at Soc Gen.

Brian, I had two questions.

Firstly, Mad Dog 2. I wonder if you can talk a little bit about this as a very specific case of the work you're doing on improving cost.

I mean, you started with a budget of $22 billion a few years back.

Last December it was down to $14 billion.

Whereabouts are we now, and is there any clearer timing on the FID?

And then secondly, on the Downstream on fuels in particular.

The result was really very material, 40% ahead of market expectations.

Apart from margins, can you talk a little bit about trading profit and cost reductions?

In other words, the other factors that have helped in the quarter?

Thank you.

Okay.

On Mad Dog Phase 2 I think there still is a reasonable chance we'll get it FID'ed before the end of the year.

I don't think I can give you any more updates on that.

If you look at what's happening with rig rates right now, there's no question that moving it sideways will, from a value perspective, if you come back to value over volume, it will be absolutely the right thing to do.

We're seeing now rigs, deepwater rigs, I think the last time I looked there is something like -- at the end of 4Q we had 13 rigs stacked.

I think that number now sits at 21 rigs stacked.

And at the end of last year and the first quarter this year, there's 41 have been highlighted as potential that will be scrapped.

I think the rig market is still looking pretty soft right now.

So I think Mad Dog Phase 2 gets stronger.

But I would expected it to be FID'ed this year, at least there's a reasonable chance it will be FID'ed this year.

On the Downstream result for the second quarter, we did talk about a strong trading result.

Maybe just to sort of give you a little bit of guidance on that.

It was in the ballpark of $300 million to $400 million stronger than what we typically would have seen for an average quarter from our oil trading results, similar to sort of what we saw in the first quarter 2009 in terms of performance.

So something around $300 million, $350 million better than what an average quarter would be for oil trading.

Thanks so much.

Will go now to Martijn Rats of Morgan Stanley.

Hello.

I just wanted to ask you two things.

First of all, the charge related to the Deepwater Horizon incident of a little more than $300 million.

Last quarter it was a little bit more than $400 million.

And I know these things are taken as normal operating items.

But is there a quarterly run rate for this now?

I wanted to ask you if you provide some ideas around that.

And secondly I wanted to ask about Egypt where you've taken an important FID that is quite sizable at quite an interesting point in the cycle.

Now from where we're sitting, admittedly behind our spreadsheets in offices, Egypt is not known for paying very quickly nor for very high gas prices.

I wanted to ask you what gave you the confidence to do this now?

What are you seeing in the project that makes it so attractive?

Well, Egypt is a great project, which I'll come back to.

But maybe we'll just pick up the business economic loss claims.

As you all know, that in terms of our provisions going forward, as a result of the various decisions that were taken around business economic loss and the appeals that we made, if you recall we had the matching issue, which is known as 495 we won at the Fifth Circuit Court of Appeal.

And then the issue on causation wasn't actually seen by the Supreme Court.

But we're now back into sort of a more stable steady state now with the facility in Louisiana.

And so what we will do is take business economic loss claims as they arise each quarter, both in terms of determinations and paid.

Anything over and above the $20 billion we now take to the P&L in NOI, and this quarter it was $300 million associated with business economic loss claims.

We'll attempt to make a provision of this once we have a patent of payments.

The facility closes on June 8 for all final claims of this year.

And then I think it will probably take a couple of quarters before we'll be in position where we can make an actuarial calculation to come up with the provision around this going forward.

I should also point out, Martijn, because it's pretty important that of course that cash comes out of the $20 billion trust fund which still has something in excess of, if you take away the fisheries piece that's left, $3.5 billion of cash to be dispersed to various pieces, including the PSC settlement.

So that's on business economic loss claims.

On Egypt, we've got a very long and successful track record of over 50 years and something close to $25 billion of investments in Egypt.

We're one of the largest foreign investors there.

I think the project that we've announced around the West Nile Delta is one of the most significant developments we'll look at.

There's five fields involved.

It utilizes all the existing and new infrastructure inside Egypt.

It goes into the domestic gas market that's priced off international prices.

I think there's something like five -- we've mentioned on the call five TCF of gas.

And so we see this from an economics perspective as being a very deep and important strategic investment for BP over many, many decades into the future.

And I think it's a great opportunity.

It builds on our gas portfolio, as we said on the call, around Oman-Khazzan and Shaktonese Phase 2. And we see the great project going forward.

All right.

Thank you.

Next question from Chris Copeland of Bank of America.

Thank you.

Thank you, Jess.

Thanks, Brian.

Just two question.

Firstly, on your trading again during Q1.

You commented on the impact that had on your cash flows.

I just wonder whether we've seen a lot of that in terms of the earnings impact, or given that this is about contango, you expect this to trickle through into already Q2 or even later in the year.

So just understanding how the timing works in terms of cash flow versus earnings?

Would be great to get some hints.

And then I noticed your slide where you talk about $20 billion CapEx budget, now sees $20 billion almost as the upper end of a scale that could potentially have downside.

Just wondered whether you already have any comment to make on where the journey is going to take you into 2016, and whether you are worried, or whether you think we should be worried about decline rates possibly edging towards the higher end of your range that you've guided us towards in the past?

Thank you.

Thanks, Chris.

I think -- on that last question, I think the thing that we're very conscious of is making sure that at this point, as Lamar and his team has gone through the whole list and series of projects and will continue to do that, to make sure that we don't jeopardize the future growth that we see.

So I think this year we've talked about the cuts in exploration.

We've talked about looking to reposition the capital budget.

We're being very cautious about what we do for 2016.

We will expect to see, as I mentioned earlier through some anecdotes around the engineering CapEx savings that we can come in the subsea and the control systems, that we will start to see some deflation naturally come into that capital budget for next year.

There's some deflation this year's $20 billion, but not that much compared to what we would expect through into 2016 as the oil prices continue to remain fairly soft.

I think it's too soon to say at this point.

It's something we'll come back later in the year on future quarter calls.

But it's something we're very, very cognizant of in terms of what choices we make to make sure that we don't damage the potential for future growth further out down the curve.

In terms of the oil trading result, of course I can't tell you.

All I'd observe is that in the early part of the first quarter we saw contango structures of up to $13 in WTI and $8 in Brent.

I don't think we ever got to the floating storage economics, because I think it's about $1 a month is what you need per barrel to go to floating storage.

So I don't think we actually got that far to that.

The curve has flattened out quite significantly.

We allowed our oil trading business, as we have done historically, to put certain positions on around those contango market structures.

And the profits associated with those will unwind through the year.

As you know, we'll use mark-to-market accounting.

And therefore we won't realize those profits until later that in the year.

The profit we booked in 1Q for contango is relatively modest, in the tens of millions, certainly not the hundreds.

Okay, that's great.

So you'd agree with a statement that says you saw a lot of it in cash flow but not a lot in earnings, which is about to come?

No.

So the $1.4 billion that we invested in contango stocks, those positions will unwind as the year progresses.

Yes.

Okay, thank you.

Next question from Theepan Jothilingam of Nomura.

Yes.

Hi, good afternoon.

Thanks, Jess.

Brian, Just I want to come back to your cash balance.

It's impressively increasing in this environment.

I know you're raising debt.

So I just want to understand what you thought the optimal level in terms of cash is?

Would you consider raising more debt through the rest of this year?

And then I'm sure you've run different scenarios, and you've talked about in the past, in the event of a penalty being announced by the District Judge.

Could you just talk about scenarios, would use cash?

Do you see a greater likelihood that BP would post a bond against any liability?

And just run through any potential scenarios that might arise in the coming months on the back of any announcement.

Thanks, Theepan.

You saw our net dept rose through the quarter as we are in balance in terms of sources and uses of cash.

We've continued to raise debt.

I think we raised $7 billion in the first quarter at very attractive rates.

We will continue to look to be able to tap those debt markets at different opportunities as they arise.

But we continue to manage the overall portfolio in terms of cash that we're holding a deposit.

In terms of the penalty phase, that I would fully expect that at some point the District Court, there will be a ruling around Phase III.

I think post-trial briefs went in on April 24.

So it is in the hands of the District Court.

We could hear a ruling on Phase III at any time.

And that will simply set a number for BP Exploration and Production Company to then have a discussion in terms of how that is dealt with vis-a-vis bond or cash.

And that's really a matter for BP Exploration Production Company, and one that we'll come back to on future calls, I'm sure.

Fred Lucas of JPMorgan.

Thanks, Jess.

Afternoon to you both.

Just one question around the cash flow framework and dividend prioritization, which is clear.

I'm just wondering if you could help, Brian, on the cash flow bridge?

So just looking at Q1, which I know is an odd quarter in many respects.

But taking the quarter's cash flow of $1.9 billion, adjusting from a condo which was $0.7 billion.

And then, as you referenced, the inventory associated with contango of $1.4 billion.

That gets you to around $4 billion,.

I wouldn't call it normalized cash flow but something closer to a normal cash flow for that type of quarter.

Annualize that, that's about $16 billion, just under.

But clearly you need to get to a cash flow balance, dividend costing just under $7 billion, CapEx $20 billion.

So I'm wondering, the bit that's missing, how should we think about that?

Is that a combination of billions of dollars of cost savings, headcounts, (inaudible), et cetera?

And also some macro improvement, I guess?

I guess even though you're bearish, you're seeing things get better from $54 Brent.

And is there also another piece we should consider, because you seem to be referencing CapEx deflation much more to come in 2016?

Should we be thinking about $20 billion of CapEx actually falling to $16 billion, in which case we only have to make $23 billion?

So I can see how we might bridge that.

So can you give us a bit of help bridging that gap, please, Brian?

Yes, Fred.

I mean, it's [one turning] a quarter, right?

So I wouldn't -- I think I spent most of last year on the $30 billion to $31 billion target saying, please don't multiply a quarter by four.

Although actually as it happens, it probably would've worked out for the first quarter.

So I wouldn't just take the first quarter.

But I think what you see in the first quarter is the full impact of where the oil prices have now appeared to settle.

And there could be still some downside from where we are, and there may be some short-term respite in terms of upside that we're seeing at the moment.

If you go back to your simple math, I think you can probably add $1 billion of working capital build as well that we talked about, which would get you to a number of around $5 billion.

But our real focus going forward is in terms of how we rebalance sources and uses.

So we are keenly aware that where we got to last year was that we had something like a $3.8 billion surplus in terms of operating cash versus CapEx and dividends.

We know we need to get back to breakeven going forward in terms of balancing up those sources and uses of cash.

And that's what we'll work on each quarter.

And actually I think you've answer the question yourself.

Some of it will come through deflation in terms of capital.

So you'd expect to see some deflation coming through.

And I've given you some examples of that in terms of the subsea and control systems where we're seeing up to 20% and 30% reductions on specific projects.

And of course a big part of this will be actually the overall cost base coming down, to get that back in line with the $50 to $60 a barrel that we see today.

I think it's all of the things that you described, Fred.

And we'll continue to report it quarter by quarter going forward on that.

Okay, fair enough.

And just quickly on the rig cancellations, which cost you $375 million.

Are there any more imminent?

As you see the rig right now, does it still makes sense to be considering canceling any more?

We've let one other one go, which came up for expiree, which was from memory the Enterprise, I think it was in the Gulf of Mexico.

So we're down to nine rigs in the GOM.

With those two more cancellations, we'll be down to seven rigs in the Gulf of Mexico.

And we continue to look at the rig portfolio.

We continue to look at the cost base, the projects that we are moving -- some of the projects we're moving sideways.

And we will continue to reevaluate it.

And you may see more to come going forward.

As I said earlier, it's still a very, very soft rig fleet right now, with the end of the quarter 21 deepwater rigs stacked.

And just finally, and hope it's not a silly question, Brian, but do think BP needs any protection from the UK government?

That's not a silly question, Fred.

That's a leading question.

That's a very leading question.

It's not one that I'm going to comment on.

Our focus here at BP is being on delivering the things that we said we'd deliver for our shareholders.

We laid those out back in 2011 around the 10-point plan.

We're now in a period of resetting the Company through this lower oil price environment and then we'll come back with you what the future growth of the Company looks like.

But I'm not going to get drawn on those sort of questions.

No, thank you.

Okay.

Thank you, Brian.

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

Thanks very much for taking my question.

Maybe going into the portfolio a little bit.

Looking at Iraq.

I think I read you're taking more cargos from Iraq in the past month.

And possibly I wonder also in 1Q.

Is there any change in the amount that's contributing to the cash flows coming in or going to change as you recover more cargos, or any comments around that?

More broadly, on the North Sea, I've got a question for you, Brian.

How do you think that basin resolves itself?

On the one hand, you read over the weekend unions lamenting a war on wages by oil majors and complaining that they're not being paid enough to do too much.

On the other hand there are the service companies saying they're not going to do any more North Sea fabrication work because all the previous ones blew over their budgets and made the cost too high and not achieving enough.

Do you feel like there's an impasse there, and what's your role in resolving it?

Well, maybe just to come to Iraq first.

As you are aware, there's a lot of problems in the north and the west of the country.

And so far we're virtually untouched in Rumaila in the south.

We continue to work with the government around lifting.

You've seen further liftings.

of course as we take liftings, it's not surprise you should see those increase with the lower oil prices.

As the oil prices have come down, of course, in terms of renumerating the investment you need more liftings.

You'll start to see that as a trend going forward.

But we are working locally with the Iraq government in terms of how we manage that program.

Is there an any quantities you can put around it in terms of cash impact?

No, not at -- we wouldn't normally get into that level of detail by asset.

But no we're managing it like we do other positions that we have around the globe.

And that's where the benefits of a portfolio come in as different locations go through different cycles.

North Sea, I think you mean you have to recognize, we're 50 years in, or in our 51st year in.

We had the 50th celebration last year for the North Sea.

And it is a very, very late life province.

And we are having to deal with all the issues that we have to deal with with a late life province in terms of maintenance and investment and investments that going into the kit.

Our focus is very much around some of the big new developments around Clair Ridge and Quad 204.

I think the recent changes to the tax fiscal regime in the North Sea will help, but that won't be sufficient.

And I think the companies, and working with the service contractors, we have to come up with a solution to make sure that the North Sea continues to be strong going forward.

And that's what we're trying to do.

Around our new big investments we're investing significant billions over the next 5 to 10 years in those big projects that we talked about.

And this year we've had reliability improve, as we've seen from [Canool] and Roman Andrew through the quarter.

But you have to accept the fact that we're in this late life development of the asset and it's really about how we renew it going forward.

I think it's a matter for all parties involved in the North Sea.

Were you profitable in the North Sea in 1Q, can you say?

We don't normally give, again, specific guidance on an asset within a region.

All right.

I'll stop asking.

Thank you.

Okay.

Thank you.

And we have no further questions being polled.

So with that, I'll leave it to Brian to make a few last remarks.

Great.

Thanks, Jess.

Well, look.

Thank you for taking the time today.

This is just a one first quarter for the year.

We are going through massive changes in the industry, as we can see with where the oil prices are today.

We continue to believe that the oil prices will remain soft.

And our mission will be continue to be able to reposition the Company going forward to make sure that we bring everything back into balance.

And will continue to report each quarter going forward on our progress against that.

So thank you very much for taking the time today, and I look forward to speaking to you at the second quarter with Bob.