英國石油 (BP) 2009 Q3 法說會逐字稿

Welcome to the BP presentation to the financial community webcast and conference call.

I will now hand over the call to Fergus McLeod, Head of Investor Relations.

Welcome to BP's third quarter 2009 results webcast and conference call.

I am Fergus McLeod, BP's Head of Investor Relations.

Joining me today is Byron Grote, our Chief Financial Officer.

Before we start, I would like to you take a moment to read this next slide.

As usual, during our presentation we will be making forward-looking statements.

Actual results may differ from these plans or forecasts for a number of reasons, such as those noted on this slide and in our SEC filings.

Thank you.

And now, over to Byron.

Thank you, Fergus.

Ladies and gentlemen, good day and welcome to BP's third quarter results for 2009.

As usual, I will begin my review of the quarter with the trading environment.

The table shows percentage year on year changes in BP's average upstream realizations and the refining indicator margin for the third quarter, as well as year-to-date.

Compared with last quarter, our liquids realization increased by 20% to $63 per barrel.

Our average gas realization was flat versus last quarter at $2.80 per thousand cubic feet.

In the United States, our gas realizations increased, despite the small drop in the Henry Hub marker due to a narrowing of regional differentials.

Taking oil and gas together, our 3Q and year-to-date average hydrocarbon realizations were around 50% lower than a year-ago.

Our refining indicator margin was $3.40 per barrel in 3Q, down 30% compared with the previous quarter and about 60% lower than a year-ago.

BP's actual margin declined by less than the indicator due to differences in energy costs, and product mix assumptions.

On a nine-month basis, the refining indicator margin was down by 30% compared with 2008.

Margins have remained weak in October.

Turning to the financials.

Adjusting for $300 million in nonoperating items and fair value accounting effects, our underlying replacement cost profit was $4.7 billion, down 47% versus last year, reflecting the much weaker environment.

Compared with last quarter, it is up by 60%, reflecting higher oil prices and stronger operational and cost performance.

The 3Q effective tax rate at 29% is lower than previous guidance, reflecting a higher proportion of income from equity accounted entities, primarily TNK-BP, foreign exchange effects, and adjustments to tax provisions.

We now expect the 2009 full-year rate to be around 32% to 33%.

Third quarter operating cash flow was $8.1 billion, down 46% compared with last year, but up by 20% compared with last quarter, again reflecting strong operational and cost performance.

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

In exploration production, after adjusting for nonoperating items and fair value accounting effects of $650 million, we reported a pre-tax underlying replacement cost profit of $6.3 billion for 3Q, down $5.2 billion compared with last year, reflecting the significantly weaker price environment.

Production exceeded 3.9 million barrels of oil equivalent per day, 7% higher than a year-ago.

This increase reflects continued strong operational performance and the absence of hurricanes so far this year.

Adjusting for the effect of hurricanes on last year's production, third quarter production was 4% higher.

Compared with the second quarter, earnings benefited from a greater percentage of higher margin barrels -- in particular, from the Gulf of Mexico.

We maintained momentum in reducing costs, with unit production costs down by 18% on 3Q 2008 even after adjusting for the effect of last year's hurricanes.

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

BP's share of TNK-BP net income was $730 million for the quarter and we received a dividend of $250 million.

The result benefited from strong operating performance and $100 million disposal gain.

Our distinctive track record of exploration success continued with the announcement of the giant Tiber oil discovery in the deep water Gulf of Mexico.

The well was drilled to total a depth of over 35,000 feet, making it the deepest well ever drilled by the industry.

In Iraq, we're awaiting formal approval of the technical services contract to develop the super giant Rumaila field, won by BP and CNPC in a bid round in June 2009.

Finally, subject to government and parliamentary approval we will be farming into the on shore Risha concession in Jordan in the northeast of the country as a partner with the state-owned National Petroleum Company.

In refining and marketing, after adjusting for nonoperating items and fair value accounting effects of $155 million, we reported a pre-tax underlying replacement cost profit of $1.1 billion for 3Q.

While this is a decrease of about $250 million compared with a year ago, it is a strong performance in a materially weaker refining environment.

The refining indicator margin is less than half the level seen in the third quarter of 2008 and upgrading margins continue to be poor.

This performance reflects good progress in both operations and costs.

Our refineries are running well, with 3Q availability over 94% and throughputs up by nearly 150,000 barrels per day versus a year ago.

For the 9 months, our underlying result improved by 34% relative to the same period in 2008, despite average refining indicator margins having fallen by 30% year on year.

In the fuel value chains, our efficiency program continues to deliver significant cost reductions.

The international businesses continue to perform well, with strong contributions from lubricants, global fuels, and petrochemicals.

Petrochemicals volumes were over 20% higher than 2Q and also up versus last year.

And we have continued to focus the footprint of our business with the disposal of company-owned and operated sites in the United States and the announced sale of our ground fuels business in Greece.

Looking ahead to the fourth quarter, with new capacity coming onstream, we expect petrochemicals margins to be under pressure.

In refining, turnaround activities are expected to be higher than in the third quarter.

In other businesses and corporate, after adjusting for $60 million of nonoperating items, the third quarter's result was a charge of $520 million, down $630 million compared with a year ago.

This year on year change was primarily due to negative foreign exchange effects and a much weaker margin environment for shipping and solar, partially offset by continued reduction in corporate costs.

Turning now to cash flow.

This slide compares our sources and uses of cash in the first nine months of 2008 and 2009.

Operating cash flow was over $20 billion.

In addition, we received nearly $2 billion of disposal proceeds.

We used this cash to fund around $15 billion of organic CapEx and pay around $8 billion in dividends.

We indicated at the start of 2009 our intention to balance our sources and uses of cash in an oil price environment of around $60 per barrel.

We're making good progress in achieving this goal, as evidenced by a positive net cash flow for both the quarter, and over the past six months in spite of much weaker than expected refining margins and North American gas prices.

This progress can also be seen on our net debt ratio, which ended 3Q at 21% and remains at the lower end of our targeted band.

Looking forward to 4Q, net debt will be impacted by the normal year-end factors.

Our strategy remains on track.

In the upstream, we are ahead of our indicated growth trajectory.

In the downstream, operating performance has been strong, with refining availability more than 5% higher than last year.

Across the group, we're driving greater efficiency.

Year-to-date cash costs are down by more than $3 billion and we now expect a full-year decrease of around $4 billion, twice the level projected at the start of the year.

We continue to high-grade our portfolio with $2 billion to $3 billion of disposal proceeds expected in 2009.

And we're continuing to invest to grow the company, with projected organic capital expenditure of around $20 billion for the year.

This concludes my remarks.

Fergus and I would now be delighted to address any questions.

(Operator Instructions).

Thank you, operator.

The first question is from Theepan at Morgan Stanley.

Theepan, are you there?

Hi, good afternoon, gents.

I had three questions, all in the upstream.

Firstly, Byron, you mentioned headline growth is ahead of your projected growth.

I was wondering if you could talk through perhaps the moving parts for the rest of this year and more importantly into 2010 in terms of ramp up start ups and declines, and in particular focusing on Tangguh and Thunder Horse.

Second question just on cost.

I think, in the release you -- BP indicated an 18% reduction in unit costs in E&P.

I was wondering how much of that is energy related?

What I am trying to understand is how sustainable that is going forward.

Lastly, on Block 31, I just wanted to find out what the next phase of development would be, post-PSVM.

Thank you.

Thank you, Theepan.

I will cover the first two and Fergus can provide an update on Block 31.

As far as upstream growth goes, we will speak more specifically about the 2010 timeframe when we have our strategy update in the first quarter.

As far as what is currently happening, it is really a case of great operational performance across the whole portfolio.

This is the type of operations that we have been aiming to achieve, and what we saw in the third quarter was the delivery of that.

We are currently benefiting from the continued ramp-up of production in Thunder Horse, as you indicated, which continues to perform beyond expectations.

And as we look into the fourth quarter, we will start realizing benefits from Tangguh.

We have got both trains one and two currently operational, and are in the process of ramping up LNG production.

So, that will be a factor in 4Q, and of course, traditionally we see the cycle of higher production in 4Q driven by gas offtakes and various other operational factors.

So, you will tend to see that.

The biggest change versus the 2008 timeframe is obviously we leave the third quarter without the operational disruptions we had last year as a consequence of hurricanes.

At least so far in the fourth quarter, we continue to benefit from that.

As far as cash costs go, maybe I will take the question and talk to it more broadly than just in the upstream.

As far as -- where is it coming from, between 50% and 60% of the benefits are a consequence of our own actions.

The rest is a combination of two factors.

Foreign exchange benefits, which come from a stronger dollar, and lower fuel costs.

If you look at what I mean by our own actions, there is the restructuring and simplification efforts we have talked about quarter by quarter.

The absence of business disruption costs, primarily there in the downstream but, the absence of those that we have experienced in the first half of 2008.

But really, across the entire group, cost efficiency measures which are bearing fruit.

If I take the over $3 billion that we described and I try to split it between the segments, about two-thirds of that reduction is in refining and marketing, but I should add that refining and marketing encompasses about two-thirds of the cash costs of the group.

So it is in line with its underlying cash cost contribution.

And it is really, again, it is everywhere across the group.

And we're continuing to see that benefit flow through to the bottom line, not only in the earnings side, but also on the cash side.

Fergus?

Great, thank you.

And just moving on to Block 31, Theepan, there is no new news beyond PSVM at this point.

As you know, that is a project in which we have 27% working interest over plateau production rate of 150,000 barrels a day or so.

That is one that's under development at the moment.

As we go on to the other potential developments in Block 31, clearly one of our big learnings the last decade is that more time spent in the front-end engineering phase of these projects tends to give us better projects with higher returns.

Although everybody talks a lot about production growth, equally important is capital efficiency in terms of delivering the growth in financial returns.

At the end of the day, that is what we're focused on -- not volumetrics, that we're targeting for the next phase.

As those projects are approved, we will give you more details and you can anticipate an update in the early part of next year with the [adjusted] presentation on that.

The next question comes from Lucy Haskins at Barclays.

Congratulations on a very good set of number.

Could I ask -- a bit more on the tax guidance, Byron, and what you would be -- if you could give us any steer as far as 2010?

And also, within the downstream business, if there is any color in terms of what was marketing and what was refining?

Hey, Lucy.

Let me cover the tax rate first.

I realize that this came as a bit of a surprise to the analysts out there.

Quite a bit better than anticipated.

We outlined in the stock exchange, three factors -- the higher proportion of income coming from associates and jointly controlled entities, which I will remind everybody is included in pre-tax income already net of tax under IFRS -- I won't justify why that occurs, but that is the way it works -- foreign exchange effects, and adjustments to tax provisions.

And I have -- it came more or less equally from those three factors.

As far as next year, I have indicated that the full-year rate for 2009 is now expected to be between 32% and 33%, which is down from the original guidance, back in the first quarter of 36% to 39%.

As far as next year goes, the current expectation is it will fall somewhere in between those two areas.

It won't be as high as 36% to 39%.

I doubt it will be as low as the 32% to 33%, because this year has been impacted by some factors that we wouldn't expect to be repeatable, in 2010.

As far as the fourth quarter goes, let me just sort of bring it home closer in 4Q.

The thing about the fourth quarter is that there tend to be a lot of volatile factors.

So consistent with last year, there can be surprises.

But the number that we have guided you to in the stock exchange announcement is the way we see it today and -- in the absence of unforeseen movements in prices or exchange rates or a lot of other things, it shouldn't be too far afield from that.

Thanks, Lucy.

Next question comes from Jason Kenney up in Scotland.

Hi there.

Well done, very good results.

I just wanted to go back to that higher proportion of income from associates and the tax guidance effect.

Is that all disposal proceeds, that jump?

Or is there something else I'm missing?

The reason I ask is because if you look at the TNK contribution to [BP], it was lower Q on Q, and I am trying to just work out, if it is just disposal or something else.

Jason, let me give you a little bit of background.

Because there is a -- I think it is a bit technical, but in order to answer your question I need to go down that dimension.

In line with IFRS, what we do is we base our quarterly effective tax rate on a forecast for the year as a whole.

That means we -- it is smoother at the front end of the year, and can be much more volatile as we move the latter quarters -- in particular, the fourth quarter as I described earlier.

The proportion -- so, we base it on forecasts for the year.

The proportion of earnings coming from equity accounted entities in 3Q, plus our updated projection of 4Q, is greater than the forecast that we had in place back in July.

So there is a forecasting element as well as the actual delivery in the quarter.

And, if I look at it from another direction, this updated forecast also reflects the greater proportion of earnings coming from these associates and jointly controlled entities in the second half than we saw in the first half.

So, you can't actually just look at one quarter in isolation and come to the conclusion that you have, Jason.

I think Fergus has something.

To put numbers behind what Byron just said, Jason, if you look back at the first quarter and look back at the group income statement, you can see that earnings and jointly controlled entities and associates accounted for just over 11% of group profit before interest and taxation compared to the 16.2% we saw in the third quarter.

So that makes the point that Byron just made about how the proportion has risen over the year and that has affected the reported group tax rate.

Thank you very much.

Thank you, Jason.

Now, across to Ireland, Mr.

Peter Hutton with NCB.

It's across to London, actually, but never mind.

Just a gain on costs.

The cash costs are running at $3 billion annual rate, and $4 billion for the year, two questions on that one.

What is the offset on increase in noncash you need to offset on that one?

And another one on costs.

When we look at the costs in the upstream, against the Brent price, there is normally an extremely strong correlation -- actually of around 95%.

And in fact when we look at this, you made exactly the same money at exactly the same Brent price as in 2Q 2007 -- which implies as an outsider that the cost that you have recovered the inflation we saw in 2008 and we're back to something like the costs that we saw in 2007.

With the increase that you're expecting by the end of the year, is there still further to come and that is from the rollback of inflation?

And what is the implication for 2010 in terms of the $4 billion run rate that you expect by the end of the year?

Can we expect something like $5 billion as a nice round number?

$5 billion to $6 billion?

Any guidance on 2010 cost savings?

That was quite a very large question this you asked there.

That's why I didn't ask the second one.

Peter, if I have got your first part of your question right, you wanted to know what offset there is on noncash versus the over $3 billion worth cash savings so far this year?

Is that correct?

That's right, yes.

We had indicated that DD&A would be running about $1 billion a year more in 2009 than it had in 2008.

And that's pretty much on track as we go into the last quarter of the year.

So against the more than $3 billion in cash, cost savings, about $1 billion in noncash.

I just point out for everybody that we -- that we have included a little definition of cash costs at the front of stock exchange announcement, which attempts to explain how you could relate it to the broad categories which are incorporated in the income statement, the distribution administration expenses and production and manufacturing expenses.

So, hopefully, you found that useful.

Fergus will pick up at least the first part of the second question.

Thanks.

Great question, Peter.

But I hope we're going to do a little better than your question is implying.

I mean, you saw that in the third quarter, the year-on-year decrease unit costs was better than the 11% or 12% reduction we had seen earlier in the year, and that was driven by three things.

High-grading of activity, more efficient execution, and the new supply chain benefits, which where I think your question was focusing.

You're quite right that as you see the oil price rise, we would expect to see something of a headwind developing from the supply chain.

It is inevitable if the recent rise in oil prices is sustained.

But the first two parts of what's driving reduction in our unit costs - the high-grading activity and the more efficient execution - will very much continue.

And indeed we're having great success with procurement and that aspect of the more efficient management of the activity we execute.

So I think you would be overly pessimistic to expect us to revert to the cost structure of 2.5 years ago, even if we were to see the oil price go back to where it was.

In respect to 2010, too early to give any guidance there, but again, it would be reasonable to expect us to be updating you on that in the new year.

Thanks a lot.

Hopefully, I will get this right -- across the Atlantic to Robert Kessler at Simmons and Company.

Robert, are you there?

I am.

That's right, I'm in the US.

Just looking at your US natural gas production, it started to roll over a bit in the third quarter versus the second quarter.

Wondering if you might be able to split the offshore Gulf of Mexico component to that rate of change versus onshore Lower 48 and provide some indication as to where we're likely to head as we go into 2010 for base declines in the US Lower 48?

Well, we don't have that breakdown available.

Fergus and his team perhaps can dig it up subsequent to the webcast.

We have focused our activity onshore.

We're seeing a great response from the shale gas areas that we acquired in our deal with Chesapeake a year ago.

And we're driving our own onshore activity to ensure that it is responsive to the environment we're in.

Just to underscore that, in spite of the fact that in the third quarter we had Henry Hub gas prices of below $4 an MCF, the North American gas unit, which is responsible for the onshore operations there, was both profitable and cash generative.

So they have taken up the challenge here quite substantially.

Fergus, there is something -- ?

No, we just actually managed to dig out those numbers for you, Robert, and in fact actually when you see the aggregate North American gas number, you're absolutely right -- it does show a decline.

But the pattern to it is the Gulf of Mexico's contribution continues to rise, that the Lower 48 contribution is essentially flat.

And almost the entirety of the decline in Q3 over Q2 was in Alaska, which I suspect is related to maintenance operations and the seasonality of gas out there.

As you know, we have [efficiency in the shared operation].

Sure.

Good, thanks.

Primarily in Alaskan from early on.

And I assume that you would still expect as you did in May that with the growth in shale, notwithstanding the drop in activity, you expect relatively flat production from your overall operations for gas.

That's right, yes, and we have actually the resource potential for increases if the economic environment justifies that.

Thank you.

Right.

Coming back to London, we have a question from Alejandro Demichelis at BofA Merrill Lynch.

Alejandro, are you there?

Yes, just one quick question.

You were mentioning you continue to invest for growth in the company, and with the new contract in Iraq coming and so on.

How is that we should be thinking about CapEx going into next year then?

It is premature to provide specific guidance until we have actually got the contract finalized.

It will be an additional amount of capital spending CapEx going into next year.

But of course, it will take awhile to get fully ramped up in our operations.

So, it is a factor.

But it is well contained within our thoughts of appropriate amount of capital spending in 2010.

Okay.

Great, thank you.

Great.

Okay.

Thanks Alejandro.

Now over to Mark Bloomfield at Citi.

Mark, are you there?

Good afternoon.

Two questions, please.

First of all, US gas realizations moved higher despite a negative quarter on quarter evolution of markets.

I just wonder if you could give color on that result and if there is any unusual contribution from trading?

And secondly, in light of recent successes in your drilling efforts in the Gulf of Mexico, I just wonder if you could offer color on your forward program in that region both for exploration and appraisal over the next 12 months?

Thanks.

Okay.

Let me cover realizations and your trading question.

Yes, it is a consequence of regional differentials shrinking.

The Rockies Express is open, allowing the evacuation of larger quantities of gas out of the Rockies area.

So, in our producing areas, we have seen a considerable step down in the regional differentials, which means realizations head north even as the Henry Hub Price has declined a bit.

And, you wouldn't see it in the realizations anyway.

But, as far as the trading contribution from our gas trading group, which is part of exploration & production, it's in line with what we consider a normal quarter.

Thanks.

Thanks.

Mark, would you just repeat the second part of your question?

Not sure I caught it correctly.

Yes, of course.

In light of obviously some recent successful drilling efforts in the Gulf of Mexico, I wondered if you could give color on the forward program for both exploration and appraisal in that region over the next 12 months or so?

That's the sort of thing that we tend to cover when we go through the strategy presentation.

Andy will be able to give additional guidance on that in a few months time.

It is clear with the success we're having in the Gulf of Mexico, that that is a key focus of our investment activity, both in the near term and as we go forward.

But as far as specific guidance on the broader range of activity set up that you have requested, I think that is best left until the first quarter.

Okay, thanks.

That brings us on to a web question, which can you please confirm the expected timing of results from the Kaskida appraisal well.

I think I will take that, and tell that you well is still drilling and there is nothing to report obviously while that well is still underway.

Coming back to London, we have got a question from Irene Himona with Exane.

How are you?

Good afternoon.

I had two quick questions, please.

First in US gas, last December your colleagues in Houston spoke of reaching or working to reach cash breakeven at around $4 Henry Hub.

I wonder how far you are from that.

And secondly, could you just clarify if within the $4 billion cost reduction targeted for this year, you include TNK-BP's cost cutting?

Thank you.

As far as US gas goes, just refer back to my previous comment, Irene, that we are -- in the third quarter, we operated at cash positive out of the North American gas organization.

So they have -- they were targeting to get down to $4, and essentially they have accomplished that already.

And as far as the $4 billion in cost savings, no, that doesn't include any contribution out of the associates and jointly controlled companies at all.

So to the extent there is savings going on in TNK-BP, that doesn't translate into the numbers I have indicated to you.

Thank you.

Thanks, Irene.

Now to Paul Spedding of HSBC.

Good afternoon.

More of a general question, whether you can give us any feeling as to what the BP -- or what BP is seeing in terms of demand for products, for gas that might give us any indication how the -- particularly the OECD economies are doing?

Paul, that is the crystal ball question, isn't it?

All right.

What we're seeing is, whether it is in our oil products area or in gas demand, things are stabilizing at the current time.

So we saw very large year-on-year reductions as we went through the first part of 2009.

But as the situation has stabilized across financial markets and stabilized across wider economic activity, we're seeing things running now pretty much equivalent year-on-year, and in some areas actually running ahead of where they were this time last year.

Thanks very much.

And now on to Lucas Herrmann at Deutsche.

Lucas, are you there?

Good afternoon, gentlemen.

Two if I might.

The first was on refining.

Byron, you indicated in your introductory comments -- and your trading update indicates as well -- that the refining markets have deteriorated as we have gone into the fourth quarter.

What I find very difficult on this side of the desk is to get a strong sense of what the contribution from the different business lines within marketing is, or within refining and marketing is, and the extent to which the deterioration in refining and markets is actually going to impact heavily or otherwise on your business as a whole.

So the question very simply is whether you can give us some greater breakdown of the contribution from the various different profit streams.

Secondly, I just wanted to ask about a dividend.

I suspect you will tell me to wait for the strategy day, but it has clearly been a huge point of focus for investors.

The company now is -- looks very comfortably cash break-even should we say at around $60.

If you were sitting in my shoes today, Byron, and you have got to make some -- give some indication on what you think BP is likely to do with its dividend going into 2010, what are the main factors that you're likely to consider?

Historically you distributed excess cash via buybacks.

That has probably involved buying shares at possibly the wrong time in the cycle.

And I think the market is giving you precious little credit for it.

You reemphasized dividend two years ago with a very large increase.

How should one be thinking about your thoughts around dividend now?

Sorry, Lucas could you repeat the first question?

I lost it while you were talking about the second one.

Sorry, the first question was just some better color really on the profit stream within the refining business and how to think about profits in refining in Q4 given the deterioration of refining markets.

We basically get at this stage of the game one indicator from you and one profit -- one real indicator from you, which is refining margin, which profits are based around.

Clearly there are many things which are driving the profits of that division, and it is very hard on this side of the desk to get the sense of what is likely to happen going into Q4, given stability of certain profit streams.

Well, I can appreciate that, Lucas.

As far as refineries go and the contribution from them as a stand-alone entity, it is something we're really not tracking ourselves any more.

We have organized the refineries into integrated fuel value chains.

We tend to think about that part of the business on an integrated basis from the point at which it takes supply to the point at which it is delivering product to an end user.

And we have felt, as I believe Iain Conn has indicated to investors a number of times in the past, that looking at it on an integrated basis as opposed to various slices does open up the opportunity to not only reduce costs, but to realize substantially better margins.

And by operating that way, then clearly we need to think about it as a whole.

All right.

I hear you.

If I can interrupt.

But there are two profit streams -- international business and fuel value chain.

Is it possible to break down the contribution towards the $900 billion in refining of those two streams?

Maybe I could help on that one, Lucas.

Clearly it moves around quarter to quarter.

But just to help you out here, fuel value chains remain overall profitable as Byron indicated.

The refining bit of that, if you could separate it out, would obviously have been under pressure given the margin structure we saw in the third quarter.

But overall fuel value chains remained profitable around perhaps one-third of the results, and the other two-thirds coming from the international businesses.

Thanks.

You saw the rise in petrochemicals volumes; that clearly helped there.

Lubricants continues to perform well, as does aviation.

So I think you get some sense.

Certainly there is a lot of potential on the fuel side for improvement as and when the environment does improve.

It is no doubt, Lucas, that the international businesses as Fergus is saying has been a very strong kernel of profitable operation for BP over the course of the last couple of years and continues to do that.

In the meantime, Iain and his team are working very hard to get the fuel value chains able to deliver profit and to deliver cash, even in difficult environments.

As far as your dividend question, well, I guess I have to say I'm not sitting in your shoes, so I have to speak from our perspective.

What we have indicated as far as the dividend itself is that it is our intention to grow it with the underlying financial growth of the firm.

And at the current time, we just gotten back to the point where we're able to think about things in a cash breakeven perspective.

And we always have to think about the balancing act here between investments for the growth of the firm, the dividend, and how it pertains to current shareholders -- how we utilize the balance sheet to deal with the various ups and downs of the environment.

What I would say is as far as share buybacks go and picking up that thread of your question, is that at the current time, I certainly don't envision any share buybacks by BP.

We certainly would be looking to do other things with cash, rather than buying back shares at the current time in the current -- what I would say, very delicate and uncertain environment.

Thank you.

Now on to Jon Rigby at UBS.

Hi.

Two questions.

One I guess, picking up the theme from Lucas a little.

Your gearing as you noted down was towards the bottom end of your range.

Is it reasonable to assume, given the delicate nature you pointed out of the current market, that you intend to keep gearing down towards the bottom of the range for the foreseeable future just to give yourself a cushion?

And the second is just on the downstream.

I think Iain talked about a performance gap of about $4 billion or so back in March.

Taking your comments upon where the benefits have fallen in the first nine months of the year, can we assume that essentially he has delivered the closing of that gap?

And if he has, is there more upside -- given I think it is geared to -- you might correct me, to the assumption around the GIM.

And therefore, are you able to indicate what other benefits might accrue if refining margins move back up towards your mid cycle assumption?

Thanks.

Thank you, Jon.

I will cover the first one and Fergus will pull together a response for your second question.

Yes, we're at the bottom end of the range.

And the whole point of staying at the bottom end of the range is as you indicated, you have got the cushion in case something unanticipated occurs.

So it's our preference to be there.

To the extent that nothing unforeseen occurs, then we would certainly plan on remaining in that range, as indeed we have attempted to over the course of the last three or four years.

Fergus?

Thanks for the question, Jon.

I've got to say, internally we are very pleased with the progress that is being made addressing the performance gap that Iain Conn has been talking about over the last couple of years.

We indicated back in February we thought we had closed about half of it by the end of 2008.

If indeed you look our current income per barrel -- admittedly a very crude measure, but if you do look at that, in aggregate we're performing at least as well as in fact in many cases better than the main competitors.

But I don't think that means we have run out of juice.

I think there are at least four factors that would indicate the potential for further momentum, financial momentum in refining and marketing.

And the first thing is, there are some parts of our business that are performing extremely well.

I mentioned international businesses, and indeed it is true of some of our fuel selling chains, but by no means all of them.

Those businesses continue to build on successes and we believe they have further momentum in the next few years.

Secondly there are some of the other fuel value chains that are not performing so well.

And you can see some insight into that through the lens of our geographical disclosure.

Certainly we're extremely focused on turning around the performance of those fuel value chains.

I think you can expect some significant financial leverage from those efforts, again over the next couple of years.

And thirdly we are increasing the capability of our portfolio to capture margins that are available by making new investments.

The most significant those is the Whiting upgrade.

That is due to come onstream in 2012.

It will transform the ability of the Midwest fuel value chain to capture margin by transforming the nature of its input in terms of raw materials.

Last but not least, and you referred to this yourself -- we have to leverage to the environment.

The first three factors clearly are independent of the environment.

But as you know through the rule of thumb, every $1 on refining margin is an excess of $1 billion in terms of operating profits.

All of those things say there is very significant performance potential.

Can I follow-up for a second?

In the normal course of events or -- not normal course of events, but in the future, would you expect the US to be running at a profit in the kind of conditions that you have seen in the third quarter?

We would certainly like that move to that place, Jon.

It is not straightforward, but we have made huge progress over the last year.

You work out the rule of thumb impact, of the change in the environment relative to last year, and then you look at US profitability this year relative to last year, and you get a sense of the magnitude.

They have come a very long way already, and they have got further to travel and they know that and they are very targeted on doing that.

Jon, this is Byron.

If you adjust out for the fair value accounting effects and nonoperating items, the US business in aggregate was only a very small loss.

So the amount of space they have to close is very small and there is a lot of effort in motion.

So I would certainly believe that it would be able to get the US operations in a profitable zone in 2010 in a similar environment.

Certainly that I know is what Iain and his management team are very much determined to do.

Thank you.

Thanks, Jon.

Now, Neil McMahon at Bernstein.

Neil?

Back on the costs.

Question.

I think if you look over the cycles in the industry, the last time we saw a significant drop in unit costs was arguably back in 1998 to 1999 when all the mergers took place and more importantly, we had very low oil and gas price.

Frankly, since then on a unit basis, everybody's costs have gone up, and it is pretty hard to see where the cost savings have been in a rising commodity oil price and gas price.

So really just trying to get a handle on it.

If we had natural gas prices move back to $6 to $7 Mcf in the US, what would that actually do to your cash costs, or overall cost targets?

And the second question, again, related to costs, could you give us some examples of any areas where you have been able to reduce oil service costs for today and for the future through negotiations this year that will affect the CapEx as we roll forward?

Thank you, Neil.

What -- I think the best way to look at it, because I don't have a crystal ball and nobody has a crystal ball as to what the world would be like if prices were different than they are today.

The only thing I can speak is to what is going on today.

And what is occurring is that we are continuing to see price deflation, occurring within the sector.

And we're on top of that realizing additional benefits from the procurement efforts that we put in place, and we have -- I believe we have substantially improved our performance in that area.

So we're seeing the benefits coming through along both dimensions.

Now, that isn't to say that all parts of the service sector are in a deflationary mode and, and as prices as you're suggesting start firming, certainly on the oil side as they're sitting north of $70, we're starting to see some underlying upward pressures.

But it is all in a flux right now.

And I don't think that it is possible to determine what is an equilibrium position given the yo-yo ride in which prices have progressed over the course of the last 18 months.

So, sorry to be less help helpful than you may have hoped, Neil, but I think there is a lot of dynamic issues here on both the demand and supply side that are yet to sort through.

the only thing I can say is -- we are very much focused on cost in all parts of our organization, in particular with the big leverage that exists on costs in the upstream, and we're going to fight it even if the environment does turn out to be a bit more inflationary than we're seeing today.

Just to build on what Byron said, it would be a very nice problem to have to see US natural gas prices back at $7 Mcf.

But I think the history of that business shows it is a margin business.

Yes, you're right that the correlation between price and cost there, but certainly the profitability and the free cash flow do expand significantly in a stronger environment.

Through the cycle that business has been extremely free cash flow generative.

In terms of your point about examples of how we can reduce costs in a way that will impact on CapEx in 2010 and beyond, and the correlation with the commodity price -- yes, that's true but it all depends on where you start.

And certainly the benchmarking work we've done suggests we do have room to travel actually to get to the level of the most efficient project executors.

We're in action on how we might close a considerable part of that gap.

So watch the space.

There's a question from the web here, which is why you have changed your organic CapEx guidance for 2009 from below $20 billion to around $20 billion, and what are the implications for 2010?

Thank you, Fergus.

First, I need to say this is a very small change.

We expect the outcome to be in the $19 billion to $20 billion range.

The pace of spend to date, organic spend to date, is just a bit over $14 billion.

And the fourth quarter is typically a higher-than-average spend quarter in its own right, averaging 30% of the capital spend over the course of the last several years.

So that will put it on track for, as I say, something in the high [19s] or $20 billion this year.

As the environment has evolved in the year, we have adjusted activity at the margins.

So, we have kept an eye towards prices coming up in the oil sector, and have been investing as we have gone through the area in line with the growth strategy that we outlined in the first quarter at our strategy presentation.

As far as next year goes, we will provide specific guidance in 1Q.

But to assist you a bit and in line with the strategy that we have outlined in March, I have already talked about the deflationary benefits we're seeing and the procurement benefits, as both Fergus and I have mentioned.

And the potential of -- as oil prices are at $70, we have seen some inflation.

So costs are a key here and, in line with the answer to the previous question, we have to take the way we see it today.

As a firm, we have said that we intend to balance our sources and use of cash in about a $60 oil price environment.

And to invest at a level that is necessary to be able to grow the firm.

And, it just -- again as a proof point, that is what we're doing today with the capital spending program of around $20 billion.

So whether you look at it through the inflationary lens or you look at it consistent with the growth guidance we have given, or you look at it through the lens of what can we afford to spend in a $60 oil price environment, it all leads to pretty much an answer not too far afield from what we're spending in 2009.

All right.

Back to the telephone.

And we have a question here from Colin Smith at ICAP.

Colin?

Good afternoon, gentlemen.

Quick first question, and that is just thinking about the throughput sales and the production you achieved and the portfolio you have today, would it be your view that that was pretty much as good as it can be or do you think you could do more than that?

So like efficiency of use of throughputs and production, was that as good as it can be?

The second question was completely different.

And that's on your deal with Rumaila.

There is a lot of word in the press that all the deals have sort of happened because the tax is only going to apply to the production fee and maybe not to other elements in the overall remuneration.

I just wanted to check whether you are getting the same deal, because I think that deal has been initialed rather than signed off yet, and we have further discussions attached to it.

Thank you, Colin.

Let me handle the first question and then pass it to Fergus.

There is a -- a long road yet here to travel.

And we believe there is the ability to yet further take costs out of the system to drive greater efficiencies and overhead, to drive greater operating efficiencies -- as well as in some parts of our company, to access additional revenues.

So, there is benefits both on the revenue side and the cost side yet to be unlocked.

And I think that we have got considerable distance to go yet.

So don't think that the third quarter of 2009 is as far as we can go to improving the operations of BP.

We're confident there is much more to show in the fourth quarter and years ahead.

It wasn't so much a cost question.

It was just, for example, can you push refinery utilization to even higher levels than those you have achieved on a sustainable basis?

I appreciate the point you have been making about cost saving.

It was more to do with the volume components both downstream and upstream.

Well, as far as the general availability, we're not going to be able to push the refineries to having much more availability once they get into the levels that you have seen in the third quarter.

But there still is considerable range to operate them more effectively on a day-to-day basis, to be able to generate greater margins out of the refineries both by the inputs delivered to them, the way that they run, and the products they produce.

So I think it is the wrong way to look at it is to just focus on the operating availability line, because underneath that there is a wealth of opportunity to continue to improve performance.

To build on that, Colin, to think about the planning and execution of turnaround activity is another area which is a massive opportunity actually in terms of financial performance improvement.

Looking at the upstream we don't give you region by region numbers on terms of operational efficiency.

Some areas are doing extremely well.

Other areas still have a ways to travel.

And I can assure you that that particular avenue for improvement has still got very significant mileage in it.

On your question on Rumaila yes, you're absolutely right.

We're still awaiting final approval from the Iraqis for the contract to develop the giant Rumaila field, which we won with the NPC in the bid round back in June.

We're very happy about that contract.

It's a great opportunity to work with people in the government of Iraq to develop what is one of the world's greatest oil fields.

We see it as the beginning of a very long-term relationship with Iraq, and the contractual terms we're negotiating reflect the quality of assets and quality of the opportunity, and I think you will find that it is competitive with other opportunities in our portfolio.

and certainly being the first to have signed, or the first have agreed to accept the terms offered in the bid round in June means you will find we're not disadvantaged in any way when that contract is finally concluded.

Moving back to the US, you have been very patient, Mark.

Mark Gilman at Benchmark.

Thanks very much.

I had a couple of specific things.

First, can you give us any guidance as to where the remaining dispositions in terms of the 2009 forecast Byron suggested are likely to be sourced to?

Is it just retail or are there other items?

Secondly, the exploration write offs in the US in the quarter were quite large.

Can you itemize at least to some degree, what went in there?

Thirdly, foreign gas production in the quarter was quite a bit weaker than we thought it was going to be.

Can you highlight any areas that might have fallen off, particularly from second quarter levels?

Finally, with respect to Rumaila, can you discuss at all whether you will be carrying the Iraqi government's interests and any measures you would take to reduce the risk relating to cost recovery?

Thanks very much.

Thank you, Mark.

Sorry, I have lost your first question, as we went down --

Remaining dispositions, Byron, for 2009.

No, the -- some retail will indeed feature in that because we still have some COCO stations -- company owned company operated stations in the US to dispose of.

We don't talk about M&A activity.

It is only the things we have already announced that come into play.

We're [1.6] of the way through the $2 billion to $3 billion target.

So, we feel comfortable we have it in hand.

As far as exploration write offs, they come in chunks.

Sometimes it is a small number.

Sometimes it is a bigger number.

Write-offs of exploration wells these days come in mighty big chunks, and by definition given the cost of individual wells.

But we don't speak to the specifics of that.

We haven't in the past and I am afraid I can't help you today, either, Mark.

And as far as Rumaila goes, we're certainly not planning on any specific things with respect to cost recovery, but the terms and condition are clear in the contract.

And your final question, Mark, which is about non-US gas.

Just looking country-by-country here.

The variation between the third quarter and the second quarter is all about maintenance activities and seasonality.

There is nothing structural in that, and there is nothing to be read into that.

Some down Trinidad, Egypt a little bit, others a little bit up, but it is to do with operational and seasonal and maintenance issues, more than anything else.

Thank you, guys.

Thanks.

Back to the UK, and I think we're almost at the end of the questions now.

Neill Morton at MF.

Neill, you have been very patient -- are you still there?

I am indeed, Fergus, thank you.

Actually I have another question on Rumaila, but I guess it is more macro oriented.

You're talking about tripling production within about seven years.

I appreciate that it's early days, but could you perhaps give a comment how quickly you think you could ramp that up or, for example, whether the ramp up would be gradual, steady, or more lumpy in nature?

Thinking again from the macro point of view, adding that level of production even over a number of years -- isn't it a sort of fairly chunky edition to global supply growth?

And then secondly, on Ghana -- I guess somebody has to ask a question on Ghana -- you said earlier that you're interested in the country.

I appreciate there are many ways to skin a cat, so to speak, but isn't there an implicit strategy to partner with a national oil company rather than participating in asset auctions per se, thank you?

As far as Ghana goes, I think I need to be very clear.

We don't respond to any sorts of questions about M&A activity or other market rumors of that sort.

So, that is actually a standard response, Neill.

As far as the first question goes, Fergus?

On Rumaila, clearly with us still in the final phases of concluding the contract, it wouldn't be appropriate to go into too much depth.

But a little context may help.

Let's remember what asset we're talking about.

65 billion barrels of oil in place.

Probably the third largest oil field in the world.

12 billion barrels recovered so far and probably 20 billion still to come, which would take recovery factors to around 40%, which given that kind of field and that kind of reservoir is very credible.

Now we in our former incarnation discovered the field in 1952.

We worked on it for a long time.

Over the past five years, we have been working with the Southern Oil Company, exclusively, providing them with technical support.

We know a lot about the reservoir.

We understand the rocks and we think that the aspirations of the Iraqi government have got for the field are realistic actually.

And we're going to help them carry it through.

I think we have time for one more question.

And that question comes from David Klein at RBS.

David, what question would you like to ask?

Can I just go back on the cost reduction issue?

In terms of the self-help component that you said was 50% to 60% of the total that you're claiming, you diagnosed that as restructuring simplification on one hand and absence of business disruption costs on the other.

Can you say which of -- can you plot the relative scale of those two items?

First question.

If not specifically, then say which is the bigger.

Secondly, in terms of the absence of business disruption costs, presumably that fades out on a quarterly basis at some point.

When does that item fade out?

That item has already been fading out as we have gone through the year.

It was a big factor when we looked at 1Q versus 1Q.

I quantified it at that stage.

But as we progressed through the year in 2008, we were moving beyond that.

So we're already in the -- in the phasing where that is no longer an issue, on a year-to-year basis.

Okay.

So the majority of that 50% to 60% is the restructuring, straight simplification.

Yes, and just general cost efficiency measures across the Company, 1,001 things that are being done, consistent with the motto Every Dollar Counts, which is held dear by everybody working at BP.

Many thanks.

I'm afraid we're out of time.

I apologize to any of you whose questions we haven't been able to get to this afternoon.

It has been a busy call.

Please call us at Investor Relations and we will follow-up with you.

I would now like to pass over to Byron for concluding remarks.

Thank you, Fergus.

In closing, I would just like to make one final comment.

These strong 3Q results reflect the focused agenda we have been pursuing for the past two years to grow the upstream business, turn around the downstream, and to drive simplification and lower cost structure throughout the group.

Continuous improvement, and by that I mean each year being better than the last, is the basis for the plans we're building and the delivery we're targeting.

Quarter-by-quarter, we're building track record of improving performance and we are determined to maintain it.

Thanks for joining us.

Have a good day.