英國石油 (BP) 2010 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 Fergus McLeod, Head of investor Relations.

Hello, and welcome to BP's first quarterer 2010 conference call.

My name is Fergus McLeod, BP's Head of of Investor Relations, and today's presentation will be by Byron Grote, our Chief Financial Officer.

Just before we start, I'd like to draw your attention to our cautionary statement.

During our presentation today, we will make reference to estimates, plans and expectations, that are forward-looking statements.

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

Please refer to our annual report in accounts and first quarter stock exchange announcement for more details.

Both of these documents are available on our web site.

Thank you.

And now over to Byron.

Thank you, Fergus.

And good day to those joining us on this call.

You will all be aware of the tragic incident last week on the Transocean Deepwater Horizon drilling rig.

Our thoughts go out, at this very difficult time, to the families, friends and colleagues of those affected.

BP continues to do everything it can to respond to the incident, and has put into place a comprehensive plan for both oil well intervention and spill response.

Working with the US authorities and Transocean, we will ensure that the group's full resources are behind the efforts to control the well, and to ensure that there are no serious environmental consequences.

We will continue to provide regular updates on our progress.

I will now begin my review of the quarter with the trading environment.

The table shows the percentage year-on-year changes in BP's average upstream realizations and the refining indicator margin.

Our liquids realization of $72 per barrel, was up 6% on 4Q and was over 70% higher than a year ago.

Out gas realization increased to $4.26 per thousand cubic feet, up over 15% on both the previous quarter and a year ago.

Taking both oil and gas together, our total average hydrocarbon realization was up 7% compared with 4Q '09, and was 57% higher than a year ago.

The refining indicator margin of $3.08 per barrel remained weak, being 50% lower than a year ago.

Turning to the financials, adjusting for a charge of $50 million for non-operating items and fair value accounting effects, our first quarter underlying replacement cost profit was $5.6 billion, an increase of 120% on the 1Q '09 result.

This strong performance reflects higher hydrocarbon realizations, continued operational momentum and lower underlying costs partially offset by a weaker supply and trading contribution, lower refining margins and higher DD&A.

First quarter operating cash flow was $7.7 billion.

Up 38% compared with last year.

The $0.14 per share dividend announced today, which will be paid in June, is the same as a year ago.

Shareholders approved the proposal to offer the choice of receiving a script dividend at our recent annual general meeting.

The script dividend program will be available for this and future dividend payments.

Turning now to the performance of the businesses, in Exploration Production, after adjusting for a gain of $100 million for non-operating items and fair value accounting effects, we reported a pre-tax underlying replacement cost profit of $8.2 billion for 1Q, up $4.3 billion compared with last year.

This reflects an improved price environment and continued underlying operational momentum.

The contribution from gas marketing and trading was lower than the strong result of last year, but still within the typical quarterly range.

Production again exceeded 4 million-barrels of oil equivalent per day, broadly flat with a year ago, and 1% higher after adjusting for entitlement impacts in our production sharing agreements.

We have maintained momentum in reducing costs.

After adjusting for restructuring charges, unit production costs were 3% lower than a year ago.

DD&A is higher than a year ago, in line with previous guidance.

The first quarter result also reflected a low exploration write-off similar to last year.

BP's share of TNK-BP net income was $540 million for the quarter, and we received a dividend of $260 million.

In refining and marketing, after adjusting for a net charge of $60 million related to non-operating items and fair value accounting effects, we reported a pre-tax underlying replacement cost profit of $790 million for the first quarter.

Pre-tax underlying replacement cost profit was down by $760 million compared to the first quarter of 2009, primarily due to a weak supply in trading contribution in contrast to the very strong first quarter of 2009.

The result was also impacted by a weaker refining environment with the indicator margin at around half the level of the same period last year, and marketing margins for some products compressed by rising crude prices.

These factors were partially offset by further cost efficiencies and by continued strong operational performance in the field value chains with both availability and throughput significantly higher than the same period last year.

In addition, BP's actual refining margins fell by less than the indicator margin would suggest as a result of BP's highly upgraded refining portfolio.

The international businesses which include aviation, lubricants and petrochemicals, continue to perform well with petrochemicals volumes up almost 40% compared to the same period last year.

From a regional perspective, underlying performance in the U.S.

improved by $500 million from the fourth quarter primarily driven by delivery of further cost efficiencies.

Looking ahead to the second quarter, our turnaround activity is expected to be higher than in 1Q.

The indicator margin has improved in the early part of the quarter although we expect opportunities for further improvement to be limited.

Continued low market volatility will limit the supply and trading contribution in the quarter.

And finally, as new petrochemicals capacity comes on stream, we'd expect those margins to also come under pressure.

In other businesses and corporate, after adjusting for a charge of over $100 million for non-operating items, the first quarter's result was a charge of $210 million, an improvement of $230 million on a year ago.

This improved underline result versus 1Q '09 is primarily due to favorable foreign exchange effects and lower cost, and margin improvement in alternative energy.

Guidance for 2010 remains unchanged from that given in February 2010, with underline quarterly charges volatile, and averaging approximately $400 million each period.

Turning now to cash flow, this slide compares our sources and uses of cash in the first quarter of 2009 and 2010.

Operating cash flow was $7.7 billion, up $2.1 billion versus a year ago.

We use this cash to fund $4.3 billion of capital expenditure and distributed $2.6 billion in dividends.

Our net debt ratio was 19% at the end of 1Q.

This is below the bottom of our targeted band providing us significant head room to finance the recently announced Devon transaction.

Before closing, I like to say a few words regarding the outlook for the rest of the year and our strategic progress.

Consistent with guidance, we expect production in 2010 to be slightly lower than in 2009.

In the second quarter, we expect a normal, seasonal turnaround effect of 100,000-barrels a day.

These turnaround activities are planned for some of our highest margin areas, including the North Sea and the Gulf of Mexico, where activity is currently underway at Thunder Horse.

This will impact costs and margins as well as volumes.

We are continuing to take action to reduce our cash costs.

In spice of adverse effects from foreign exchange and fuel costs, first quarter cash costs were slightly lower than a year earlier.

We continue to expect organic capital expenditure for the year of around $20 billion despite less than ratable spending in the first quarter.

Our [disposable] program is on track with the bulk of proceeds expected in the second half of the year.

Effective tax rate for the first quarter was 34%, in line with our previous guidance.

Our strategy remains on track.

In exploration production we are continuing to see strong momentum.

The transaction with Devon Energy gives us a material position in Brazil, deepens our incumbent position in the Gulf of Mexico and Azerbaijan and enable us to accelerate the development of the Kirby asset in Canada.

In line with our strategy, this opportunity offers long term growth potential with an emphasis on high margin barrels leveraged to the oil price.

In Iraq, the first major contracts to support the expansion of production from the Rumaila field were awarded.

Our new centralized developments organization became operational on the first of April.

This will drive greater capital efficiency by centrally managing all major projects across the upstream.

In refining and marketing, we are continuing to make progress in delivering of efficiency and improving portfolio quality.

Our refinery availability in 1Q was over 95%, the highest since 2004.

We announced two further transactions to simplify our portfolio with the pending sale of our French retail business, and our exit from five countries in Africa.

In alternative energy we took another step toward improving the cost competitiveness of our solar business with the announced closure of manufacturing at our Frederick, Maryland, facility.

In wind, the business continues to grow with construction started on our ninth U.S.

wind farm.

Throughout the Corporation, the focus is on efficiency with further progress in reducing overheads at all levels.

To have efficient operations, they must be safe and reliable.

Across BP, safety remains our number one priority.

The 1Q results reflect the momentum that we have across the group and we were determined to maintain it.

That concludes my remarks.

Fergus and I will now take your questions.

(Operator Instructions)

Thank you, Operator, and the first question comes from Theepan at Morgan Stanley in London.

Please go ahead, Theepan.

Yes, hi.

Good afternoon, gents.

Two questions on the upstream, please.

Firstly, just on Macondo -- I know, probably were a bit of a last question asked.

But, despite being extremely early days, generic question, could you clarify whether there is an sort of immediate impact or changes you are making to how you are running of the upstream efforts in the Gulf as a result of last week's incident?

And just secondly on the Devon deal.

Byron, I wonder if you could just give us any guidance of when you expect that deal to complete and if you have any updates on any potential pre-emptions?

Thank you.

Thanks, Theepan.

I expect we will have a number of questions about the Gulf of Mexico.

But, in response to your question, at the current time we haven't made any material changes.

Clearly, we will be looking for the underlying cause of the blowout and from that trying to determine whether or not changes in procedures need to be put in place.

But, at the current time we have no information around which to make changes.

As far as Devon, it will be completed over a series of stages in the quarters ahead.

Some parts that have will be completed in the second quarter.

And as far as pre-emption goes, there are pre-emption rights in some of the assets and it will be inappropriate for me to speculate on who might and who might not pre-empt at the current time.

Okay.

Thanks very much.

Thanks, Theepan.

Next question is from Jon Rigby at UBS, also in London.

Jon, please go ahead.

Thanks.

Okay.

Well, can you, or are you able just to talk about where contractually your obligations are with respect to what's taking place at the moment?

I'm very aware that you feel that you will obviously extend as much help, assistance and support as possible.

But just interested to know what contractually your obligations lie?

And secondly, on sort of a happier note, on your upstream, your earnings against your rules of thumb and indeed in the way that just the oil prices move, just seem to have outperformed quite significantly.

And probably more than the indicated sort of cost performance that you are talking about.

Are there other things in there that we should understand that may be transit tree or something else going on that is helping that

Let me take your second question first.

Both in the upstream and in the downstream, one of the big contributors is our continued focus on cost efficiencies, the driving out of overheads that all levels within the Company and the benefits associated with doing more activity from a centralized perspective.

And the fourth quarter tends to be heavier in the way in which costs show up than other quarters during the course of the year.

And I think that to some extent you may be playing off a higher cost quarter into a lower cost quarter.

The realizations themselves were a bit better than rules of thumb might, might indicate.

A lot of that was driven by the contribution from gas that isn't Henry Hub-based, and we do have a significant amount of such gas and that may have played into it as well.

And, of course, we had a very low exploration writeoff in the quarter, lower than it would be on a ratable basis across the year, although in line with what we achieved in the first quarter of last year.

Fergus, are there any factors that you'd like to add to that?

No, no, I wouldn't add anything to that.

As far as the Gulf of Mexico goes, I mean we -- you asked about contracts, and contracts I believe are code word here for is where does liability lie?

What I say is that our focus at the current time is totally on responding to the incident, and we can sort out the liability matters in the future.

The cause of the incident is clearly going to be the subject of investigation by the regulators as well as ourselves and Transocean.

The comment I will now make is a general comment.

So specific circumstances can, can clearly shade this.

But, but in general, Transocean was responsible for the operation of the rig vessel and its equipment including the blowout preventer and for drilling the well.

In general, the lease owners, that's BP and our partners in the field, are responsible for the costs of regaining control of the well and handling the related environmental costs.

If that helps respond to your question.

That's great.

Thanks, Byron.

Thanks, Jon.

And the next question comes from Lucy Haskins of BarCap.

Lucy.

Hi.

Couple of questions, please.

Could you give us a bit more complexion in terms of the recovery we saw downstream, so sort of might have been given by such chemicals and on what element we might be seeing from your self-help measures you kindly, sort of, quantified how the cost have moved upstream, but I wondered if you could actually quantify how they're moving downstream?

And the second question was about working capital in 1Q, because traditionally we don't seem to see a charge effectively in the first quarter stage.

Obviously the inventory effect wasn't that much.

So, I wonder if there is anything else going on that was unusual?

Thanks.

Lucy.

Perhaps I will start off with the drivers of the downstream recovery.

And you are right.

There's a whole lot of things going on in there.

One of them is, of course, continued improvements in refinery availability which due feed through to profitability, for example, Texas City did return to profitability in the first quarter and it's only one quarter but it clearly, it's a promising sign.

The international businesses, aviation, marine, lubricants, continue to perform very well.

And petrochemicals, which as you know, is embedded in our refining marketing business and Asian business, also did very well and saw some continued momentum downwards in terms of costs to improved efficiency.

So, it's a lot of relatively small things, Lucy, but all in line with the sort of objectives that Iain Conn talked about in March in terms of delivering significant underlying performance improvement over the next two to three years.

Lucy, you absolutely right.

We would normally expect a run down in our working capital in the course of the first quarter.

Currently prices increased from December 31 to the 31st of March.

So that would have an impact.

The biggest element is we have built some short term inventories over the course of the first quarter, so the natural runoff that you would expect from the disposition of barrels acquired for LIFO purposes as well as the excise tax aspect at year end were offset pretty much in their entirety by a short term buildup in working capital.

That is unlikely to be the case when we get to the middle of the year.

Okay.

Thanks for that clarification.

Thanks, Lucy.

And we've got a question from the web and it comes from Angus McPhail at Alliance Trust in [Dundee].

And the question is, of the 17 up stream projects highlighted in your March strategy presentation, how many have achieved FID to date?

Give you a simple answer to that one, Angus, and the answer is seven in the first quarter and ten as we speak now.

So those 17, clearly the FID process has been somewhat front end loaded in 2010.

But that's entirely in line with our plans and obviously satisfactory.

Coming back to the telephone, we've got a question from Robert Kessler from Simmons and Co in the U.S.

Robert, please go ahead.

Thanks very much.

Good afternoon, Byron and Fergus.

I had a question about the second quarter production outlook.

Your press release, of course, highlighted the 100,000-barrels a day of expected seasonal maintenance, some 2.5% on global production.

Is it your expectation that all other factors will generally offset each other, such that the total production decline year-on-year will be on the order of a 2.5% decline?

The answer to your question is yes.

That's the reason we provided the guidance we did.

That would be in line with normal seasonal factors, and given that, unless there is a material change in the price of oil between now and end of the quarter, I think we've properly considered the production sharing contract implications as well.

Sure, thanks for that.

And then of the 100,000-barrels a day, how much would be Thunder Horse exclusively?

And then, sort of more broadly, what is the kind of run rate, utilization rate, we should think about for Thunder Horse?

Is this year's maintenance a one off to install permanent equipment and utilization will be higher going forward?

Or should we expect every couple years to have a major turnaround there?

All facilities will have turnarounds of, of some sort.

It's the way in which you ensure you have safe, reliable operations.

We built the Thunder Horse turnaround into the -- we built it into the forecast for the year when Andy talked about it in March, 2010.

It's built into the indication of reduction of 100,000-barrels a day in the second quarter for various turnaround activities.

And clearly the availability and the throughput will increase once the turnaround is over.

What the forecast will be for a one year relative to the next, I can't speak to that at the current time.

Yes, and to be absolutely clear, Robert.

All of this is exactly the same guidance we provided back in February and March 2010, which is that full year 2010 production is expected to be slightly lower than that of 2009 and this is one of the reasons for that guidance that was provided a few months back.

Thank you very much.

Thank you.

Coming back to London, Irene Himona with Exane.

Irene, please go ahead.

Good afternoon.

I have two questions, please.

Firstly, you indicated, Byron, the reduction in costs both in the upstream and in R and M.

Could you, perhaps, quantify that reduction across the group in millions of dollars and could you say what we should anticipate for the rest of the year?

And my second question was, again in refining and marketing, you highlight a significantly weaker trading profit.

Can you say if that is significantly weaker than a year ago when perhaps it was abnormally high, or is it weaker than norm?

And could you give an order of magnitude perhaps?

Thank you.

Well, Irene, this is a question that gets asked all the time and I think you know where I'm going to go on the response to the second one.

Yes, the trading profit was down materially -- I will speak to refining and marketing first -- down materially relative to the, the extraordinary contribution that was made a year ago.

And indeed the contribution is weak, weaker than would be the norm in the second quarter.

Sorry, in the first quarter of this year.

And the primary drivers around that are that the general market conditions, as I referred to in the web cast remarks, which don't provide, or haven't provided the degree of volatility that we have seen in recent years either in terms of spreads or in terms of the structure itself, or -- nor has it provided that degree of arbitrage opportunities that we would normally expect.

In the exploration production and our gas and power trading area, it was less than again the very strong contribution that occurred in the first quarter of 2009.

But, within the range that we would expect to see contribution from that part of our trading business provide on an ongoing basis.

The nature of trading is that it will be volatile and all we are seeing is the contrasts between an extraordinary quarter of a year ago and one that is a bit weaker than normal in aggregate in the first quarter of this year.

And although we've always been willing to provide you the shape and the direction of the contribution, we have not in the past, nor will we provide you the specific quantification of the contribution from that area.

The -- As far as the costs go, we talked about the cash cost contribution and that is the flow of, of costs against a headwind of, in particular, unfavorable foreign exchange effects with the dollar having weakened -- although the dollar is still very strong, but having weakened relative to where it sat in the first quarter of last year.

That has impacted our costs by several hundred million dollars.

And in spite of that, costs remain down, our cash costs remain down a year on year.

And if you want to look at a broader evaluation of costs and you add production and manufacturing costs and our distribution and administration expenses from the income statement, you will see that that number is much larger that we tend to focus on the cash cost contribution I just described.

Thank you.

Thanks, Irene.

Now go back to the internet and we've got a question from [Newlet Mahn], Sanford Bernstein.

And that question is that given the Deepwater Horizon was on a long-term contract with BP, is there availability for you to source a replacement?

Can you give any information on the impact of your drilling program or, indeed, on your production guidance?

Well, we are confident that in spite of the fact that we are going to have to redeploy rigs in order to drill a relief well at the Macondo prospect, that we will be able to pursue a drilling program that will provide the production in line with previous guidance.

That's where we sit today and I've -- I don't expect that we will move from that position.

It is requiring some redeployment, as I said.

One thing with respect to rigs is to remember that as part of the Devon transaction we picked up a couple of deepwater rigs.

One of which will be associated with the closure of the Gulf of Mexico part of the transaction and the other rig which will be associated with the closure of the Brazilian part of the transaction.

So we do have a couple of deepwater rigs coming our way from that particular deal.

And coming back to the telephones, we've got a question from the United States from Joseph Tovey at Tovey and Company.

Can you please go ahead?

Good morning.

Yes, thank you.

Couple of questions if I just might.

Number one, I was wondering as to whether you anticipate picking up the results of the problems in the Gulf of Mexico currently in the same -- in this quarter with perhaps additional reserve for what might be happening in subsequent quarters, or is it just going to be accounted for as expended?

That was one question.

Second question is, I was wondering as to whether the -- since the Devon transaction seems to be going through several different closings, do they still have the same effective date even though the legal closings may take place at different times?

Third I was wondering as to whether the effect of the turnarounds is part of the reason for inventory rundown and whether that effect is expected to continue in other quarters and to be affecting the turnarounds in downstream as well as the upstream?

With respect to the last question, I think you're reading too much into the working capital movement.

I'm presuming that's what you are alluding to.

Yes.

There were a number of timing issues with respect to cargo deliveries and the like which created a short term increase in our inventories at the end of the first quarter.

It's -- There is nothing systematic in that, and the runoff of the larger amount of working capital that we had at the year end, which we will always see during the first part of the year, is just going to extend in this calendar year out to the middle part of the year as opposed to showing up in, at the end of the first quarter.

As far as effective dates of the transaction, the deals are closing, as I said, as they go.

Built into the contract were effective dates for the various parts.

I believe that the effective date is the same for each of them, but I don't have the details on that.

What I can tell you is that as we go through the various regulatory and pre-emption approvals as we get each section of the transaction squared away, then the deal will close and payment will go to Devon and the assets will be a part of our own portfolio.

As far as how we will account for this, it's far too early to be speculating on that.

What we will do is tell you in the second quarter what we have done.

But this is focused on the first quarter results.

And I don't know exactly what we will do.

It will be dependent how much things evolve in the course of the next couple months.

Right.

Staying with the telephones we will go to questions from Alejandro at Banc of America Merrill Lynch.

Alejandro, please go ahead.

Yes, good afternoon, gentlemen.

Couple of questions here.

Maybe you can give us some kind of indication how much you have already spent in Macondo for us to have some kind of idea of on a daily basis how much this is costing?

And the second question is, maybe you can give us a rationale behind the $1 billion acquisition of the Valhall assets, and how for you see the assets going forward?

Let me talk -- I think it's time to take a few moments and just really talk about where we are in the Gulf of Mexico, and to describe the response to the Deepwater Horizon incident.

I need to note for you that communications are being handled through a joint incident command team that's led by the U.S.

Coast Guard.

And that I'm only able to speak to information that they have already released.

The Coast Guard's providing daily updates, which can be accesses via the internet.

And the IR team will be happy to direct you to the website which is www.deepwaterhorizonresponse.com if you'd like to zone into it right now.

As a background, we believe that all accidents are avoidable.

When they do occur, a company is judged on how it responds.

And as such we are deploying the full resources of the group to ensure that a tragic accident doesn't become a significant environmental event.

Currently the top of the riser's lying on the sea floor, some 500 feet from the well head.

And the flow from the top of the riser appears to be around 1000 barrels a day.

The response program is across two broad dimensions.

Stopping the flow of oil, and continuing -- and containing the environmental consequences.

So, there's three activities that we are currently progressing to control the oil flow.

First, we have five remotely operated vessels working to intervene on the blowout preventer and get it closed.

And if we are successful on that, and they have been working on it for several days now, but if we were successful on that, that could resolve the oil flow problem in a short period of time.

Secondly, we are looking to contain the flow by putting in place a large canopy with a riser over the oil leak.

This is sort of an inverted funnel.

And then processing it on the surface with a test separator.

This been engineered in concept and it has been previously utilized to successfully in shallower water.

The issue is to make certain that it can withstand the pressure of the much deeper water at the site, and to be able to sort out the various topsides processing issues.

But, for presuming we can get all that squared away, and we remain pretty confident we can at the current time, this could be a solution in four weeks or less.

And then finally, we've mobilized a rig that will shortly spud relief well in the reservoir and that will take somewhere between two and three months.

This however is a well that we would be drilling no matter what, because the intention would be to eventually turn it into a producing well since obviously we have a commercial discovery at the site.

So that's stopping the flow of oil.

The second response program's aimed at containing the environmental consequences of the oil that has gotten to the ocean surface.

In our spill response, we deployed thirty-two vessels and five aircraft.

With the capacity to contain a much bigger spill, a 100 times bigger spill, than the one we were currently facing.

The oil that's flowing out of the well, is light, it's 37API and it's volatile with a high gas/oil ratio.

At the center of the spill, that's about 3% of the surface area of the wider sheen, the spill has an average thickness of 0.1 millimeter.

That's about the width of a human hair.

And it's subject to skimming operations.

So we got skimmers out there dealing with, with the, the central part of the sheen.

And the wider sheen, which has thickness of one to two hydrocarbon molecules, so that's very tiny, is being addressed through the use of dispersements.

In addition, we've got booms prepared for deployment to protect the shoreline as a precautionary measure, if it gets to that.

The response is being managed by the joint incident command team that consists of the Coast Guard, the MMS, BP and Transocean and its functioning extremely well with cooperative and productive relationships amongst the participants.

So we are active on all fronts here with a number of activities, some occurring now, and some which will extend over a longer period of time.

The specific cost elements associated with this is something that we've agreed with the joint incident command team that the Coast Guard will be posting on their websites starting soon.

Within the next couple of days.

So you will be able to track what sort of costs are associated with that -- with this activity at that stage.

But I can't comment on it at the current time.

And obviously, Alejandro, the cost of the relief well will cost the same as any other well in the Gulf of Mexico.

That sort of $100 million or so.

Yes.

No, that is (inaudible) really good.

Thank you.

And in terms of Valhall?

Well, Valhall is a place we know extremely well.

It's one of the world's giant oil fields.

And we believe that there is a substantial upside to the recovery factor there.

In line with, with all giant oil fields, they just get bigger over the course of time as one is able to deploy a new technology to the substantial amount of hydro carbons that are still available in the reservoir.

We've been -- we are the operator there and we know the field better than anybody else.

And we looked down the range of ways in which we believe that we can increase value through just more efficient management there, the technology I described previously in improved drilling efficiency and performance.

And it should note that the field has just gone through a redevelopment process.

And on the backside of that, we see the same side of upside that has existed in a number of other Norwegian sector, North Sea projects, that have gone through a similar sort of development.

So, we are very comfortable with it and pleased to be able to acquire larger interests in Valhall.

Yes, fantastic.

Thank you very much.

Yes, I guess it's just worth maybe adding, Alejandro, Valhall is a giant field, 3.3 billion BOEs of hydrocarbons in place, you know, as we all know, big fields tend to get bigger and it's a key part of our strategy to focus -- one strand of strategy, anyway, is to focus on giant oil fields.

Now going up to Scotland, Jason Kenney at ING.

Jason, are you there?

Hi there.

Yes, thanks for taking the question.

On Iraq, there was some headlines earlier today from Tony Hayward, I think, saying the output threshold there could be reached within 18 months.

I just wonder if you can quantify the net contributions to output for BP at that time?

And then the upside, again, for volumes that could be expected by say 2014 on top of your strategic targets, of course?

And maybe reconfirm that material cost recovery from the point of reaching that threshold could also start within 18 months, 20 months?

Once we reach the threshold -- and Tony said 18 months, we've all along said it occurred sometime in the course of 2011, it depends on the progress that we are able to make on the ground.

What I, what I should point out is that we've got the same team that worked at Samotlor, the large redevelopment that TNK-BP progress.

We have the same people now deployed and working on Rumaila So, we've got people who know what they are doing and have established a track record of making the right sort of moves to, to improve production dramatically, quickly.

The actual production timetables, the shape of how they ramp up from a BP perspective, is something that is more appropriate to wait until we were talking about this in the beginning of 2011.

At that stage we will know what sort of costs we have incurred.

we'll know how the reservoir is responding and will be able to give you a clearer picture of how the recovery of costs and the number of barrels that would be apportioned to BP as a consequence of that, is going to materialize in 2011 and in subsequent years.

Obviously it starts small and ramps up from there.

And clearly, Jason, it will depend on the oil price at the time, and -- but, of course, it is also incremental to the production guidance that we provided in March 2010 which didn't include contribution from Iraq.

Okay.

Turning back to the U.S., Mark Gilman at Benchmark.

Mark, are you there?

Yes, I am.

Thank you, Fergus.

Couple quick things.

Byron, could you address the insurance coverage which you have for Macondo that might prove to be applicable?

Secondly, I would appreciate some clarification in terms of the oil sands strategy, in the context of the Value Creation acquisition?

Can you give us some kind of resource number which is not available, I think, because Value Creation is a private company.

And what, if any, implications that acquisition, or formation of a partnership, has with respect to the Sunrise project which you are still, I think, moving toward an FID on later this year?

Thanks.

We were self-insured.

We always self-insure except in those circumstances in which it's mandated by other regulatory or partner-related constraints.

With respect to this specific incident, it's all BP self-insurance which we've determined over the course of time is a much more economic way for a Company like BP to manage its risk factors.

Fergus is going to talk about the oil sands.

Yes, you are quite right.

You know, there is a broader strategy here, Mark, on oil sands.

And you are right, there are some constraints in terms of how much we can say about this deal except to perhaps help you on these -- the resource side of it.

Terra de Grace, we think is a high quality resource.

It's incomparable in quality to the other things that we are moving forward in terms of, for example, the Kirby asset that going to move forward as part of the Devon transaction.

We are talking about a resource, in terms of recoverable resource, here that's something in excess of 1 billion barrels.

So, sorry not to be able to be more precise about it than that, but at least it gives you some sense that, you know, it's a material asset and it's a material part of, obviously, what is a developing strategy, and multistrand strategy for the oil sands.

And I just re-enforce what Fergus says.

We've got a multistrand strategy in Canada with respect to the oil sands and there is no linkage between the VCI deal and the Sunrise prospect.

We've got two Northern Tier refineries that can process a significant amount of heavy oil, and we are very comfortable with the notion that we need multiple sources to create the integrated margin capture from the upstream down through the refinery in order to best advantage our position there.

Thank you, Byron.

Thank you, Mark.

Coming back to the UK, Neill Morton of MF.

Neill, are you there?

I am indeed.

Thank you, Fergus.

I've just a couple quick numbers questions left.

Byron you mentioned the strong cash flow in Q1.

But, I noticed that your cash taxes paid were quite low.

I'm assuming that would catch up in due course.

But, you mentioned in the past that your cash tax rate tends to, sort of, undershoot your P&L tax rate by a couple of percentage points.

Is that still -- does that rule of thumb apply?

And then secondly, assuming the various Devon transactions complete by year end, what is likely the incremental Cap Ex in 2011 that we should be factoring into our models?

Thank you.

As far as the cash tax rate, it does run on average for a number of structural reasons, a few percentage points less than the affective tax rate.

How it shows up in a particular calendar year can be, in particular how it shows up in a calendar quarter, it can be very volatile and it will depend on the trend of earnings from one year to the next.

But, as a rough rule of thumb, what we've indicated to you in the past, 2% to 3% lower cash tax rate than that from an accounting perspective.

So did you catch my second question?

Yes, would you just repeat it again?

Yes, beg your pardon, I wasn't sure whether you did hear it.

Yes, just assuming the various Devon transactions complete by year end, what is sort of likely to be the incremental Cap Ex we should be factoring into our models for next year?

Too soon to give you Cap Ex guidance for 2011, Neill.

Obviously, the Devon deal contains assets that are exactly the sort of quality we want to be funding, and represent the sort of assets where we aim to increase the level of activity in the upstream as we described in our strategy back in March.

So, yes, there will be incremental activity associated with Devon in terms of its financial impact.

It will be partly offset by the improved efficiency of our capital spend which will move to the centralized development organization as one symptom of how we were moving to improve the capital efficiency of our upstream spending and exactly what that means in terms of dollars, Neill, we will provide when we provide capital spending guidance for 2011 in due course.

Two more questions remaining I think.

One from Pavel Molchanov at Raymond James in the U.S.

Pavel, are you there?

Yes, thanks very much.

After the Brazilian component of the Devon deal is closed, can you give us a sense of the time line that you envision for starting up the exploration program?

The answer to that is, Fergus and I can't give it to you at the current time.

We have been looking at the opportunities out there.

We've -- The more we look at it the more we are feeling that there are a range of attractive opportunities.

We've already been speaking with the various Brazilian authorities.

So we would expect to be able to get into action in a very efficient fashion once the deal is closed.

But the specific timing of exploration wells, I can't provide you that information at the current time.

I mean, clearly Pavel, we will sort of take up where Devon left off because the parts of the foundation for the -- our new Brazilian business unit will be the Devon personnel.

But, clearly, we also want to review with our own geotechnical perspective their plan.

So a little bit too early to answer that question specifically.

And finally, Sergio Molisani at Unicredit in London.

Sergio, are you there?

Thank you for your patience.

Yes, yes, good morning to -- good afternoon to everybody.

The first question is in the unit production costs expected for the fiscally in 2010.

We have seen unit production costs down 3% year on year in the first quarter so my question is -- considering the oil price increase it's a bit surprising.

So my question is, it's simpler get us out of this (inaudible) debt in higher cost base of first quarter of 2009 versus the fourth quarter 2009, or it's a surprising continuation of the deflation trend seen in 2009?

And the second question is, there is a lot of knowledge regarding the gas shape potential and but could commence on the potential from coalbed methane.

Could you give us some update on the Sanga Sanga project?

So, in particular in terms of timing, CapEx, and the break even (inaudible)[aspects] in terms of net present value.

Thank you very much.

Maybe.

Let's start that one with Byron.

I will deal with the first one and you can talk about coalbed methane.

Or we can do it the other way around.

Why don't we do it the other way around.

It's our objective to continue to be driving down unit production costs.

And I think Andy made the case very clearly, that we think we've got a long ways to go with respect to how we can run the Company at its optimum efficiency.

That there still are costs that we can take out, overhead costs.

There is still are far more efficient ways to, to implement and that our third party spending, the way in which we managed procurement in the past, has been such that we've never taken full advantage of the leverage that we ought to have.

So, whether it's deployment of first party costs, or reduction of third party costs, we believe that we've got considerable space.

And as a consequence, I know that Andy and his team are looking to be able to drive down the unit production costs over the course of 2010 and beyond.

But, we report on this on a quarterly basis and we will see where we are in 1Q of -- I'm sorry, in 2Q.

I would say that he is doing this in spite of the fact that these head winds of adverse foreign exchange effects are tending to drive up prices.

Over to Fergus to talk about coalbed methane.

Yes, and just to close, to answer Sergio's question about coalbed methane in Indonesia, for those who aren't familiar with this project, this is one where we have got existing capacity within the Bontang LNG plant.

So, we feel this is very exciting.

An actually quite heavily advantaged opportunity to bring new LNG to market from coalbed methane given that we don't have the expense of having to construct the LNG plant to support it.

So, where are we up to on this project?

Well, we've signed production sharing contract late last year, so all of the contractual arrangements are in place.

And what's going on this year is an appraisal program to develop a much deeper geotechnical view of the coalbed methane production capacity of the block.

So, relatively early stages but once we get into that process of appraisal and develop from the view of the capacity of the block, the lead time to actually bring it into the plan obviously is short.

So proceeding satisfactorily, Sergio, and we will keep you posted as the various milestones are passed on that project.

Thank you very much, Fergus.

I'd like to just make a final comment.

At the current moment we are fully engaged in doing everything we can to respond to the tragic accident on the Deepwater Horizon.

Firstly, control the well.

Secondly, to ensure that there is no serious environmental consequences.

And thirdly, to understand how this has occurred, and ensure it never happens again.

But at the same time, the wider BP team remains focused on the longer term agenda.

Driving safe and reliable operations everywhere, building the skills and capability of our people, and maintaining the performance momentum that we built over the last several years.

Thanks for joining us today.