BP plc (NYSE:BP) Q1 2010 Earnings Call April 27, 2010 9:00 AM ET
Fergus MacLeod - Head of IR
Tony Hayward - Group Chief Executive
Byron Grote - CFO
Andy Inglis - Head of Exploration & Production
Iain Conn - Head of Refining & Marketing
Theepan - Morgan Stanley
Jon Rigby - UBS
Lucy Haskins - Bar Cap
Robert Kessler - Simmons & Co
Irene Himona - Exane
Neil McMohan - Sanford Bernstein
Joseph Tovey - Tovey & Company
Alejandro - Banc of America-Merrill Lynch
Jason Kenney - ING
Mark Gilman - Benchmark
Neill Morton - MF
Pavel Molchanov - Raymond James
Sergio Molisani - Unicredit
Hello and welcome to BP's first quarter 2010 conference call. I'm Fergus MacLeod, BP's Head 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 estimate, 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 and accounts and first quarter stock exchange announcements for more details. Both of these documents are available on our website.
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's 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 U.S. authorities in 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 would 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 refining indicator margin. Our liquids realization at $72 per barrel was up 6% on 4Q and was over 70% higher than a year ago.
Our gas realization increased to $4.26 per 1000 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 costs 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 on $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 approve the proposal to offer the choice receiving a scrip dividend at our recent Annual General Meeting. This scrip dividend program will be available for this and future dividend payments.
Turning now to the performance of the businesses, in expiration production after adjusting for a gain of $100 million for non-operating items and fair value accounting effects, we reported a pretax underlying replacement costs 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 the 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 inline with previous guidance.
The first quarter result also reflected a low expiration write off similar to last year. BP share of the TNK-BP net income was $540 million for the quarter and we received a dividend of $260 million.
In refinery marketing after adjusting for net charge of $60 million related to non-operating items and fair value accounting effects we reported a pretax underlying replacement costs profit of $790 million for the first quarter.
Pretax underlying replacement costs profit was down by $760 million compared to the first quarter of 2009 primarily due to a weak supply and trading contribution in contrast to the very strong first quarter in 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 change, 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 indicated margin we 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 underlying result versus 1Q ’09 is primarily due to favorable foreign exchange effects and lower costs and margin improvement in alternative energy.
Guidance for 2010 remains unchanged from that given in February with underlying quarterly charges volatile and averaging approximately $400 million 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 expenditures 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 for significant headroom to finance the recently announced Devon transaction.
Before closing I’d 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 affect of around 100,000 barrels a day. These turnaround activities are plan for some of our highest margin areas including the North Sea and the Gulf of Mexico were 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 spite of adverse effect from foreign exchange and fuel costs first quarter cash cost 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 disposal program is on track with the bulk of proceeds expected in the second half of the year. The effective tax rate for the first quarter was 34% inline with our previous guidance.
Our strategy remains on track. In exploration production, we’re 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. A enables 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 leverage to the old price. In Iraq, the first major contracts to support the expansion of production from the Rumaila field were awarded.
Our new centralized development organization became operational on the 1st 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 and delivering 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 towards improving the cost competitiveness of our solar business with the announced closure of manufacturing at our Fredrick Maryland facility.
In wind, the business continues to grow with construction started on our 9th 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 are determined to maintain it.
That concludes my remarks. Fergus, and I will now take your questions.
Thank you, operator and the first question comes from Theepan at Morgan Stanley in London.
Theepan - Morgan Stanley
Two question on the upstream please. Firstly, just on the Macondo, I know it probably would be the last question asked, but despite being extremely early days, a generic question, could you clarify whether there is any sort of immediate impact or changes you’re making to have you running the other upstream assets in the Gulf as a result of last weeks incident? And just secondly on the Devon deal, Byron, I wonder if you could just give us any guidance on when you expect that deal complete and if you have any update on any potential preemption?
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 blow out 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 of that will be completed in the second quarter and as far as pre-assumption goes, there are pre-assumption rights in some of the assets and it would be inappropriate for me to speculate on who might and who might not preempt at the current time.
Our next question is from John Rigby at UBS.
Jon Rigby - UBS
Are you able to just to talk about where contractually your obligations are with respect to what’s taking place in the moment? I’m very aware that you feel that you will obviously extend as much help the systems and support as possible. But just interested where contractually your obligations lie? Secondly, on sort of a happier note, on your upstream your earnings against your rules of thumb and indeed in the way just the oil prices moved, you seemed to have outperformed quietly significantly, and probably more than the indicated at a cost performance that you are talking about. Are there other things in there that we should understand that there maybe transit treaty or something else is going on that is helping that profitability?
Let me take care of your second question first, both in the upstream and in the down stream one of the big contributors is our continued focus on cost efficiencies driving out of overheads at 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 cost show up than other quarters during the course of the year, and I think that to some extent you maybe playing off a higher cost quarter into a lower cost quarter.
The realization themselves were a bit better than rules of thumb I might indicate. A lot of that was driven by the contribution from gas that is in Henry Hub base and we do have a significant amount of such gas and that may have played into as well. And of course, we had a very low exploration write-off 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, is 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, you asked about contracts, I believe are a kind of code word for here for where does liability lie. What I’ll 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’ll now make is a general comment, so the specific circumstances can clearly shape this, but in general, Transocean was responsible for the operation of the rig vessel and its equipment including the blow-out preventer and for drilling the well. In general, the lease owner that’s BP and our partners in the field, are responsible for the cause of regaining control over the well and handling the related environmental cost. If that helps respond to your question.
The next question comes from Lucy Haskins of Bar Cap.
Lucy Haskins - Bar Cap
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. So I’ll start off with the drivers of the downstream recovery. And you are right; there is a whole lot of things going on in there. One of them is of course continued improvements and refinery availability which do feed through to profitability, for example Texas City did return to profitability in the first quarter and it's only one quarter, but clearly it’s a very promising sign. The international businesses, aviation, marine, lubricant continued to perform very well, and petrochemicals which as you know is embedded in our refining marketing business was principally an Asian business also did very well, and there were some continued momentum downwards in terms of costs through improved efficiency. So, it’s a lot of relatively small things Lucy, but all in line with sort of objectives that Iain Conn talked about back in March in terms of delivering significant underlying performance improvement over the next two to three years.
Lucy, you are absolutely right, we would normally expect a rundown in our working capital in the course of the first quarter. Clearly prices increased from December 31st to the 31st of March so that would have an impact, but the biggest element is that we have built some short-term inventories over the course of the first quarter. So the natural run-off 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 build up in working capital that is unlikely to be the case when we get to the middle of the year.
We got a question from the web and it comes from (inaudible).
And the question is, with the 17 upstream projects highlighted in your March strategy presentation, how many have achieved FID year-to-date?
I will give you a simple answer to that one [Angus], and the answer is seven in the first quarter and 10 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 very satisfactory.
Coming back to the telephone, we got a question from Robert Kessler, Simmons & Co. in the US.
Robert Kessler - Simmons & Co
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’ve 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 the end of the quarter. I think we have probably considered the production sharing contract implications as well.
Robert Kessler - Simmons & Co
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 some sort of it’s the way in which you ensure you have safer reliable operations. We built the Thunder Horse turnaround into the forecast for the year when Andy talked about it in March. Its build into the indication of reduction of 100,000 barrels a day in the second quarter for various turnaround activities, and clearly the availability and throughput will increase once the turnaround is over. What the forecast will be for one-year relative to the next, I can’t speak to that at the current time.
Absolutely clear, Robert, all of this is exactly the same guidance that we provided back in February and March which is the full year 2010 production is expected to be slightly lower than in 2009, and this is one of the reasons for that guidance that was provided a few months back.
Coming back to London, Irene Himona with Exane.
Irene Himona - Exane
I have two questions please. Firstly, you indicated, Byron, the reduction in costs both in the upstream and in R&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 am going to go on the response to second one. Yes, the trading profit was down materially and I will speak to refining and marketing first down materially relative to the extraordinary contribution that was made a year ago. And indeed the contribution is weaker than what be the norm in the first quarter of this year.
The primary drivers around that are the general market conditions as I refer to in the webcast 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 the degree of arbitrage opportunity that we’d normally expect.
In exploration production in our gas and power trading area it was less than 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 also what we are seeing is the contrast between an extraordinary quarter of a year ago, and one that’s a bit weaker than normal in aggregate, and 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 provided you the specific quantification of the contribution from that area.
As far as costs go, we talked about the cash, cost contribution and that is the flow of costs against headwind 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 cost by several $100 million and in spite of that costs remained down, or cash cost remained down year-on-year.
If you want to look at a broader evaluation of costs and you add our production and manufacturing costs and our distribution and administration expenses from the income statement, you’ll see that number is much larger, but we tend to focus on the cash cost contribution I just described.
I’ll go back to the internet and we have got a question from the Neil McMohan, Sanford Bernstein.
Neil McMohan - Sanford Bernstein
Given the deepwater rise and it 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 at your drilling program or indeed on your production guidance?
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 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 is part of the Devon transaction. We picked up a couple of deepwater rigs, one which will be associated with the closure of the Gulf of Mexico, a part of the transaction, 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 telephones, we have got a question from the United States from Joseph Tovey, Tovey & Company.
Joseph Tovey - Tovey & Company
A 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 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 since the Devon transaction seems to be going through several different closings, do they still will 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 are reading too much into the working capital movement, I am presuming that’s what you are alluding to. 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, there was nothing systematic in that and the run off of the larger amount of working capital 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 at the end of the first quarter.
As far as the effective dates of the transaction, the deals are closing as I said, as they go build into the contract were effective dates for the various parts and 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 preemption 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 part of our own portfolio.
As far as how we are going to account for this, it’s far too early to be just speculating on that. What we will do is tell you in the second quarter of what we have done, but this is focused on the first quarter results and I don’t know exactly what we will do to be very much dependant on how things evolve in the course of the next couple of months.
All right staying with the telephones, we got a question from Alejandro at Banc of America-Merrill Lynch.
Alejandro - Banc of America-Merrill Lynch
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 the rationale behind the $1 billion acquisition of the Valhall assets, and how do you see the assets going forward?
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 am only able to speak to information that they have already released, the coast guards providing daily updates which can be accessed via the Internet and IR team would be happy to direct you to website which is www.deephorizonresponse.com if you 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 a full resources of the Group to ensure that a tragic accident doesn’t become a significant environmental event. Currently, the top of the risers lying on the sea-floor some 500 feet from the well ahead 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 is three activities that were currently progressing to control the oil flow. First, we have five remotely operated vessels working to intervene on the blow-out preventer and get it closed and if we are successful on that and they we’ve been working on it for several days now. But if we are successful on that, that could resolve the oil flow problem in the short period time.
Secondly, we are looking to contain the flow by putting in place a large canopy with a riser over the oil leek. This is sort of an inverted funnel and then processing it on the surface with a test separator. This has been engineered in concept and has been previously utilized successfully in shallow 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 presuming we can get all that squared away and 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 the rig that we’ll shortly spud a relief well in the reservoir and that would 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 not 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 is aimed at containing the environmental consequences of the oil that has gotten to the ocean surface. In our spill response, we’ve deployed 32 vessels in five aircraft with a capacity to contain a much bigger spill, hundred times bigger spill than the one we’re currently facing. The oil that is flowing out of the well, its light, its 37 API and is 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 operation. So, we got skimmers out there dealing with the central part of the sheen and the wider sheen which has a thickness of one to two hydrocarbon molecules, so it’s very tiny. It’s being addressed through the use of dispersions.
In addition, we have 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 coastguard, the MMS, BP and Transocean and it’s functioning extremely well with cooperative and productive relationships amongst the participants. So, we are active all fronts here with a number of activities some occurring now and some which will extend over a longer period of time.
This specific cost elements associated with this is something that we have agreed with the joint incident command team that the coast guard will be posting on their website starting soon within the next couple of days. So you’ll be able to track what sort of costs are associated with this activity at that stage, but that I can’t comment on it at the current time.
And obviously under the cost of the relief well will cost the same as any other well in the Gulf of Mexico.
That’s sort of $100 million or so?
Alejandro - Banc of America-Merrill Lynch
No, that [historically] has been really good. Thank you. And in terms of Valhall?
Valhall is a place we know extremely well, it’s one of the world’s giant oil fields and we believe that there’s a substantial upside to the recovery factor there in line with all giant oil fields they just get bigger over the course of time as one is able to deploy new technology to the substantial amount of hydrocarbons that are still available in the reservoir. We are the operator there and we know the field better than anybody else and we’ve looked down the range of ways in which we believe that we can increase value through just more efficient management there, technology I described previously improved drilling efficiency and performance. And we should note that the field has just gone through a redevelopment process and on the back side of that we see the same set of upside that has existed in a number of other Norwegian sector, North Sea projects that have gone through a similar sort of developments. So we are very comfortable with it and pleased to be able to acquire a larger interest in Valhall.
Yeah, and I guess it’s just worth, may be adding on Andrew, Valhall is a giant field 3.3 billion BOEs of hydrocarbons in place, you know as we will know big fields tend to get bigger and you know is a key part of our strategy to focus one standard strategy anyways to focus on giant oil fields. Now going up to Scotland, Jason Kenney at ING; Jason, are you there?
Jason Kenney - ING
On Iraq, there was some headlines earlier today from Tony Hayward, I think, saying the output threshold that could be reached within 18 months. I just wonder if you could 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 have reached the threshold and Tony said 18 months, we have all along set it occurred sometime and in the course of 2011, it depends on the progress that we’ll able to make on the ground 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 got those same people now deployed are working on Rumaila. So we have got people who know what they are doing have established a track record of making the right sort of moves to improve production dramatically or quickly.
The actual production timetables of the shape of how we’ll ramp up from a BP prospective, it is something that is more appropriate to wait until we are talking about this in the beginning of 2011, if that stage we will know what sort of cost we have incurred, we’ll know how the reservoir is respond in and we will be able to give you a clearer picture of how the recovery of costs and the number of barrels that would be a portion to BP as a consequence of that is going to materialize in 2011 and in subsequent years. Obviously it starts small and ramps from there.
And clearly Jason, it will depend on the old price at a time and but of course it is all servicing (inaudible) to the production guidance that we provided in March, we didn’t include any contribution from Iraq.
Jason Kenney - ING
Turning back to U.S., Mark Gilman at Benchmark, Mark are you there?
Mark Gilman - Benchmark
Yes I am, thank you for this. Couple quick things. Byron, could you address the insurance covers 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 were still, I think, moving toward an FID on later this year? Thanks.
We are self insured we always self insured accepting those circumstances in which it’s mandated by other regulatory or partner related constraints. So with respect this specific incident its all BP self-insurance which we’ve determined over the course of time as a much more economic may for a company like BP to manage risk factors (inaudible).
I mean you’re quite right, there is a broader strategy here Mark on the oil sands and you’re right, there are some constraints in terms of how much we can say about this deal except. So that’s how you want these source resource side of it, you know, tend the grass, we think is a high-quality resource and that’s in comparable in quality to the other things that we’re moving forward in terms of for example the Kirby asset that’s going to move forward as part of the Devon transaction. We’re talking about our resource in terms of recoverable resource here that’s something in excess of a billion barrel. So I won’t be bale to be more precise about that and at least to get you some sense that it’s a material asset and it’s a material part of obviously what is the developing strategy and multi-strand strategy for the oil sands.
I just reinforce what Fergus said, we’ve got a multi-strand strategy in Canada with respect to the oil sands and there’s 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, Marl. Coming back to the UK, Neill Morton at MF. Neill you are there?
Neill Morton - MF
I am indeed, thank you Fergus. Just a couple of quick numbers questions left. Byron, when you mentioned the strong cash flow in Q1, but I noticed your cash taxes paid were quite lower. I’m assuming that would catch-up in due course, but you mentioned in the past that you cash tax rate tends to sort of undershoot your P&L actually by a couple of percentage points, does that rule of thumb still apply? And then secondly, assuming the various Devon transactions complete by year-end, what is likely to be the incremental CapEx 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 that a few percentage points less in the effective tax rate. How it shows up in a particular calendar year can be in particular how it shows up in a calendar quarter can be very volatile and it will depend on the trend of earnings from one year to the next, but as a rule of thumb what I indicated to you in the past 2% to 3% lower cash tax rate then that from an accounting perspective.
Neill Morton - MF
So did you catch my second question?
Yes, would you just repeat it again?
Neill Morton - MF
Beg your pardon, I wasn’t sure (inaudible). Just assuming the various Devon transactions complete by year-end, what sort are likely to be the incremental CapEx, we should be fractioning into a model for next year.
Too soon to give you CapEx guidance for 2011, Niell, obviously the Devon deal contains assets that are exactly the sort of quality that we want to be funding and represent a 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 is one symptom of how we are moving to improve the capital efficiency of upstream spending and exactly why it means in terms of dollars, million will provide when we provide capital spending guidance for 2011 in due course.
Two more questions remaining I think, one from Pavel Molchanov from Raymond James in the U.S., Pavel are you there?
Pavel Molchanov - Raymond James
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’ve been looking at the opportunities at the – 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 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 we cant, we will sort of take out where Devon have left off because the part of the foundation for our new Brazilian business unit will be the Devon personnel, but clearly we also want to review with our own geotechnical perspective their plans so a little bit too early to answer that question specifically.
And finally, Sergio Molisani at Unicredit in London. Sergio, are you there?
Sergio Molisani - Unicredit
The first question is in the unit production costs expected for the fiscal year 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 simply that the result of the fact that being 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, but could commence on the potential from coalbed methane. Could you give us some update on the Sanga Sanga project? So, particularly in terms of timing, CapEx, and the break even that you expect in terms of the net present value, thank you very much.
[Multiple Speakers]. I’ll deal with the first one if you can talk about coalbed methane or we can do it the other way round, why don’t we do it the other way round. It is our objective to continue to be driving down unit production costs and I think Andy made the case very clearly that we think we have got along ways to go with respect to how we can run the company at its optimum efficiency that there is still are cost that we can take out overhead cost, there is still are far more efficient ways to implement and that our third party spending the way in which we’ve 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 its deployment of first party costs or reduction of third party costs, now we believe that we’ve got a considerable space and as a consequence, I know that Andy and his team are looking to be able to drive down the unit production cost over the course of 2010 and beyond, but we report on this on a quarterly basis and we will see where we are in 2Q. I would say that he is doing this in spite of the fact that these headwinds of adverse foreign exchange effects are tending to drive up prices. Now over the Fergus, to talk about coalbed methane.
And just to clear this, to answer Sergio’s question about coalbed methane in Indonesia, for those who are not familiar with this projects, this is the one where we’ve existing capacity within the Bontang LNG plants, so we feel this a very exiting and actually quite heavily advantaged opportunity to bring new LNG to market from coalbed methane, given that we didn’t have the expense of having to construct an LNG plant to support it.
So where are we up to on this project? Well, we’ve signed a 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 much deeper geo-technical 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 a firm of view of the capacity of the block. The lead time to actually bring us into the plan obviously is short. So proceeding satisfactorily Sergio and we will keep you posted as the various mile stands are passed on that project.
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 we control the well; secondly, to ensure that there is no serious environmental consequences; and thirdly, to understand how this has occurred and ensure that it never happens again. But the same time the wider BP team remains focused on 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.
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