英國石油 (BP) 2006 Q3 法說會逐字稿

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

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

Please go ahead, sir.

Hello and welcome to BP's third quarter 2006 conference call.

My name is Fergus MacLeod, BP's Head of Investor Relations.

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

Before we start, I'd like to draw your attention to two items.

First, today's call refers to slides which we will be using during the Webcast.

As usual, those of you on our distribution list should have already received those slides by e-mail.

Second, I would like to draw your attention to this slide.

We may make forward-looking statements, which are identified by the use of the words will, expect, and similar phrases.

Actual results may differ from these plans or forecasts for a number of reasons, such as those noted here.

Now, over to Byron.

Thank you, Fergus, and good day to those joining this presentation.

Today we are pleased to announce strong results, which I will summarize for the quarter and year-to-date.

A number of one-off factors have benefited our third-quarter results, and I will highlight these as I go through my presentation.

I'll also give highlights of our continued strategic progress within the context of our financial framework.

Let me start with a summary of the trading environment.

The quarter began with oil prices at record levels in the face of supplying anxieties related to the impending hurricane season, rising Middle East tensions, and other factors.

Although oil prices softened in September, our $67 per barrel average crude realization in the third quarter was comparable with 2Q and well above that seen a year ago.

By contrast, our third-quarter gas realization of around $4.50 per thousand cubic feet was down 5% compared to a year ago, as gas prices were lower in both the United States and the United Kingdom in the face of ample supply.

Taking oil and gas together, our overall hydrocarbon realization was up 9% from 3Q '05, and 21% year-to-date.

Our third-quarter industry indicator refining margin of $8.40 per barrel is 32% lower than the hurricane-influenced peak reached last year.

Turning to the financial results, our third-quarter replacement cost profit of $7 billion was 58% higher than in the third quarter of 2005.

The per-share result was up 67%, reflecting the benefit of share buyback.

Our third-quarter profit, including inventory gains and losses of $6.2 billion, was comparable to a year ago.

These figures include significant gains related to nonoperated items, which totaled $1.2 billion post-tax.

Our results also included a number of one-off and tax and accounting impacts, which further benefited the results by around $1 billion.

I will cover these further during the segment reviews.

We generated around $5.1 billion of operating cash flow in the quarter, down 19% in absolute terms compared with 3Q '05, or 15% per share.

The reduction is mainly due to the phasing of tax payments.

The 9.825 cents per share dividend announced today is 10% higher than a year ago.

The sterling dividend is up around 4% year-on-year, reflecting the weaker dollar.

The nine-month results shown at the bottom of the page are records, as we continue to capture the benefit of the strong environment.

Turning now to the segments, the Exploration & Production results increased 52% to $9.9 billion.

The 3Q '06 result included around $2.5 billion of gains in respect of divestments and the mark-to-market accounting of embedded derivatives.

Excluding these non-operating items, the E&P result was 12% higher than in 3Q '05.

Higher oil prices and a gain on divestments in TNK-BP were offset by lower gas prices, higher production taxes, and higher costs due to continued inflationary pressures.

Adjusting for disposals, third-quarter production is up 3% when compared to 3Q '05.

This reflects growth in our new profit centers, which more than offset existing field decline and operational issues in Prudhoe Bay.

Full-year production is expected to average around 3.95 million barrels of oil equivalent per day.

TNK-BP contributed $1.5 billion to our 3Q '06 results, including a $900 million gain on divestments.

These TNK-BP figures are post-tax, consistent with IFRS reporting for equity-accounted entities.

As mentioned in previous calls, price lags built into the calculation of Russian export duties have a favorable impact in a rising market, and an adverse impact as oil prices decline.

If prices remain at current levels, the lag effect is expected to significantly reduce TNK-BP's fourth-quarter earnings.

In Refining & Marketing, we reported a pre-tax profit of $1.5 billion for the third quarter.

This includes a charge of around $430 million for non-operating item, mainly a further legal provision for Texas City.

Excluding non-operating items, our underlying result was $1.9 billion.

Compared with the third quarter of 2005, our results benefited from stronger marketing margins and a significant IFRS fair value accounting gain related to our normal supply management activity.

This was more than offset by lower refining margins and weaker supply optimization performance, higher turnaround activity, and the ongoing impact of Texas City.

Our Gas, Power & Renewables result was around $150 million in the third quarter.

Most of the changes versus last year relate to non-operating items.

These moved from a gain in 3Q '05, mainly due to embedded derivatives, to a charge in 3Q '06, primarily from the impairment of a North American NGL asset.

Excluding non-operating items, our underlying result was $237 million, around the same as in 3Q '05.

This includes a lower contribution for marketing and trading, offset by a smaller charge related to IFRS fair value accounting.

In Other Business and Corporate, or OB&C, we reported a third-quarter charge of around $260 million pre-tax.

As you may recall, we conduct an annual review of our environmental and other provisions in the third quarter, which we include in non-operating items.

Last year's review resulted in a charge of $300 million in OB&C, compared with a net credit of $100 million in 2006.

Excluding non-operating items, we reported an underlying charge of around $340 million.

Most of the change versus 3Q '05 relates to additional vacant space provisions as we continue to rationalize our real estate portfolio.

Our expected full-year underlying result remains consistent with the range of annual charges that I indicated in February.

Our third-quarter collective tax rate was 40%.

This includes the impact of the increase in the UK North Sea tax rate, which was enacted in July.

This had two effects -- first, a one-off deferred tax charge; and second, a current tax increase to reflect the 2006 impact of the higher tax rate, which is retroactive to the start of the year.

Both these effects have been recognized in the 3Q results, causing a spike in the tax rate.

This spike was partly offset by savings related to the decline in prices at quarter-end.

We now expect our full-year Group effective tax rate to average around 37% in 2006, including all of these items.

We achieved a number of strategic milestones in the third quarter.

Within E&P, we've been awarded three exploration blocks in Pakistan's offshore Indus Delta, and a coalbed methane block in India.

We announced two new discoveries -- Kaskida in the Gulf of Mexico, and Titania in Angola.

In addition, the Shenzi disposal has now been completed.

In Gas, Power & Renewables, we've concluded the acquisition of Greenlight Energy, a U.S.-based developer of wind power generation projects.

This purchase will allow us to accelerate plans to develop a leading wind power business in North America.

The newly constructed 1.1 GW K-Power plant in South Korea is now fully operational.

This joint venture represents a major component of Alternative Energy's low carbon power business, and from 2008 is expected to use LNG supplied from BP's Tangu project in Indonesia.

In R&M, we sanctioned a $3 billion investment in Canadian heavy crude oil processing at our Whiting refinery.

Reconfiguring the refinery has a potential to increase production of motor fuels at Whiting by 15%, or about 1.7 million gallons per day.

Turning now to cash flow, during the first nine months of 2006, [sources] of cash have exceeded $28 billion -- $23 billion from operations, and over $5 billion from disposals.

We used this cash to fund more than $10 billion of organic capital expenditures.

In addition, we purchased $1 billion of shares in the Rosneft IPO.

We've distributed nearly $6 billion through dividends and increased our share buyback program by 50% year-on-year, to $12 billion.

Our third-quarter net debt ratio increased to 16%.

Consistent with previous guidance, we expect gearing to return to the 20 to 30% target band at year-end, in part due to the normal phasing of working capital movements and tax payments.

Through the first three quarters we have returned around $18 billion to shareholders via higher dividends and increased share buybacks.

In September we issued $1.25 billion of shares to Access Renova as the final payment for our interest in TNK-BP.

Share buybacks in the first nine months of 2006 equaled the full-year 2005 program, and we have already purchased nearly $1.5 billion of shares in October.

Our share buyback program has reduced the average number of shares outstanding in 2006 by around 5% compared to the first nine months of last year.

This has boosted per-share measures of value significantly, with underlying earnings, operating cash flow, and production per share growing substantially faster than the absolute figures.

This is an important outcome of our strategy to grow and distribute sustainable free cash flow and our continuing emphasis on shareholder value growth.

That concludes my presentation of the results.

Fergus and I will now be happy to respond to your questions.

(OPERATOR INSTRUCTIONS).

Neil Perry, Morgan Stanley.

A couple of questions around Texas City.

One is, can you update us now on when you think you get the full financial benefit of Texas City flowing through?

You have said previously that should be in 2007.

And then secondly, I noticed John Browne's comments to the press when he was talking about the application of the safety review across the Group.

Can you give us any concept of the increased operating costs that you're looking at as a result of the new safety measures that you're going to implement, and then, presumably, will flow through across the industry?

Good afternoon.

As far as Texas City goes, we are now looking at it in full operation, so, full financial operation at the end of 2007.

And I think that's consistent with remarks that have been previously given.

We talked in the third quarter about the impact of the increased emphasis on safety and operational integrity across our operations around the globe.

John is now liking to reference this as a focus on three legs of the stool -- a focus on personal safety, a focus on protection of the environment and [approach], and a focus on process safety management.

At the time that we discussed it, with respect to our United States operations, we indicated that we expected an additional $1 billion a year to be spent.

With respect to additional process safety management issues that we would be addressing in our refining system in the United States, as well as a small component with respect to the corrosion-related incident in Alaska.

Fergus, is there anything more you would like to add to that?

The only thing I would add to that is it's a number that has gone up quite a lot.

We'd expect the '07 spend in total across the Group on safety and operational integrity to be about 50% higher than in '05.

But it's still a relatively small proportion of our cost in CapEx.

It's about 8%.

That's a number that has gone up a lot, but it's still a relatively small proportion of the overall spend, which obviously is the sum of costs in CapEx.

And the majority of that is costs rather than CapEx.

So, if you want a translate of the 8% that Fergus just said to an absolute number, that would be -- if we had our CapEx and cash costs together, that's order of magnitude $3.5 billion in 2006 -- increasing, as he said, substantially as we move into 2007, with the bulk of it, as you're suggesting, oriented towards ongoing operating expenses as opposed to capital.

Nikki Decker, Bear Stearns.

Just a follow-up on Texas City.

First of all, I was trying to reconcile the numbers that were listed in the press release and those that Lord Browne gave this morning.

It looks like the negative impact of the outage this quarter was less than a year ago.

Is that right?

If you go back to the third quarter of last year, the refinery was still in operation.

It was only shut down in its entirety as Hurricane Rita was approaching at the end of the third quarter.

So, there is quite a substantial difference between the operating loss that we are experiencing in the third quarter of 2006, which was $200 million, as John related this morning, and the operating profit that we saw in the third quarter of 2005, which was assisted substantially by the high refining margins that existed at that time in the United States.

A good calibration -- it's not a perfect calibration -- of the impact of Texas City is if you look back to the last full year in which Texas City was in operation, which is 2004, the profitability from it was about $800 million pre-tax.

So, that's $200 million a quarter compared to a $200 million loss experienced in the third quarter of 2006.

Now, refining margins have been higher than they were then, so the gap would be a bit larger.

And that doesn't take into consideration any of the knock-on effects that the limited throughput at Texas City has had on other operations, in particular our petrochemicals operations in the United States.

So, it's -- you can measure this, as you suggest, in many ways.

But a good place to begin is the difference between $200 million loss and $200 million gain when the refinery was at full operations in 2004.

How do we interpret that $320 million negative impact that you talked about in the press release?

Does that not include the charge?

If you can just clarify the number that you're referring to in the press release.

You said that the impact on associated businesses for Texas City was 320 million compared to the third quarter of 2005.

So, I adjusted that figure for the charge.

And I guess that was erroneous.

It wasn't until, as Byron said, the fourth quarter of '05 that Texas City went into loss.

It was still making an operating profit, not quite as high as the average for '04, but still a very substantial operating profit in the third quarter of '05, because the shutdown only came towards the end.

When you get into the fourth quarter, then the sequential comparisons will be against a Texas City that was shutdown in the prior period.

Does the startup of the reformer restore Texas City to profitability?

The answer is it's very dependent upon refining margins.

At higher refining margins, the answer is yes.

At today's refining margins, the answer is no.

Mark Iannotti, Merrill Lynch.

I have a few questions.

Firstly, in UK E&P the result looks pretty weak, even with quite low realizations.

Can you maybe give us some color or any more information on why that is?

Also, can you give us some guidance on the tax charge you expect for both fourth quarter and for next year, and also maybe touch on CapEx guidance beyond 2006?

Thanks.

Fergus will handle the first one;

I'll handle the second two.

You're quite right.

In the third quarter of '06, unit margins in the UK upstream do look quite weak, as they did actually in the third quarter of '05.

The principal reason is the maintenance fees and the fact you've got get fewer barrels and you're spreading fixed costs over great numbers of barrels.

Now, having said that, there are some extra factors in 3Q '06.

The first thing is the weakness of the British pound, which has given us some unfavorable foreign exchange effects when we report our numbers in dollars.

So, the cost pressure there from the weakness of the dollar.

Secondly, with some of the higher cash costs, with some inflationary pressures, obviously, across the upstream business, there's some additional integrity work that's been done during the maintenance season.

And finally, there were some high non-cash costs due to an update of our estimate of facility decommissioning costs.

So, those factors together, hopefully, explain the change in margin.

So, the dominant feature, as I said, is the fact that it is the maintenance fees, and then you will seasonally tend to get a low in underlying margins in the third quarter.

Obviously, our effective tax rate has been very volatile this year, as we've waited until the third quarter before we could book the impact of the higher supplemental tax in the North Sea.

But looking forward in the fourth quarter, and then into 2007, we would still project 37% as a good fourth-quarter number.

That will be highly dependent upon the prices at the end of the year and various other factors.

And subject to doing a full review, which we will do prior to our presentation to you in February of next year -- but subject to going through that, we would stay with the indication that we gave in February of this year, which is the longer-term effective tax rate, post these changes, also being about 37%.

On the CapEx side, we have provided guidance now for 2006; a number around $16 billion.

As we look into 2007, we would see the impact of continued safety and operational integrity spend, although, as I indicated, the bulk of that will be oriented towards operating expense as opposed to CapEx; the continued ramp-up of our Alternative Energy investment spending, building a more material presence there; the start of work with respect to creating the heavy processing -- the heavy crude processing capability increment at Whiting; as well as the continued flow-through of inflation in the E&P sector, but also impacting a number of our R&M activities.

What that all adds up to, I cannot speculate at the current time.

We will provide that specific guidance when we talk with investors in February.

But clearly, the underlying trend embedded within that is for higher capital spending in 2007.

Irene Himona, Exane BNP.

A question on TNK-BP, if I may.

Could you remind us what the level of crude and product exports was in the quarter?

And also, given the volatility in the commodity price, what has been happening to the (indiscernible) tax charges?

And secondly, if there's anything you can tell us in terms of production guidance for 2007.

Thank you.

The trend of export of products and crude oil has not materially changed.

It's been at a steady level of around 70%, or thereabouts, of the production for some period of time.

It has a little bit of volatility embedded in it.

I was just looking at the numbers Fergus was providing, and it remains in that zone in the third quarter of '06.

As far as the export duty charges, which, I believe, [is] what you're referring to, we are -- as I referenced in my remarks, we are likely to experience in the fourth quarter a phenomenon similar to that we experienced in the fourth quarter of 2005.

The lag effect of the setting of the tax reference price for export duties means that the rate that is in operation for October and November of this year drives back to the very high prices that were realized in July and August.

And therefore, we have a tax reference price for these two months of about $69.

And at the same time, the October month-to-date euros price has been about $55.

So, a very large swing with the tax reference price going up and the actual realized price coming down.

Now, it's only about a quarter of the way through the fourth quarter, and there may be an increase in the euros price over the course of the rest of the quarter.

But if prices are to stay where they are, then that would mean a very large swing as a consequence of these lagged prices in the fourth quarter, with the order of magnitude being not dissimilar to that that we saw in the fourth quarter of 2005.

The number for the combined exports of crude and products is about 68%; so, as Byron said, not much change from the prior quarter.

And the tax lag was about 130 million negative for TNK-BP in the third quarter of 2006.

And in the fourth quarter of last year it was much larger than that.

And that depends on prices at the end of the year, that we could see that again in 2006.

Any comment on 2007 volume trends, overall for the Group, I mean?

We've given a long-term indicator that TNK-BP production would increase at a rate of about 2% per annum.

We're not moving away from that indication.

That, of course, is adjusted for divestments.

What it turns out to be on one calendar year versus another calendar year basis is best left to our February guidance to investors.

And of course you'll be aware, Irene, that, obviously, TNK-BP has been making divestments this year.

So, that will affect 2007 production relative to 2006, because you'll have the full-year 2007 impact of the divestments.

So, I think, Bob Dudley, the Chief Executive of TNK-BP, has been quoted as saying reported production after divestments will be broadly flat for the next couple of years.

And that's entirely consistent with the guidance that we've given at BP.

Robert Kessler, Simmons & Co.

I was looking to see if I could get a couple of updates on your major projects.

Firstly, Azerbaijan; congrats, by the way, on the East Azeri startup.

Wondering if you might update us as to the status of Shah Deniz.

I want to say I recall expectations for first commercial gas by the end of September.

And in the U.S. at Atlantis, BHP, I believe, was mentioning commencement of only half of the gross volumes in '07 at that facility as a result of supply vessel limitations.

Can you confirm that limitation and provide us updated expectations as to when full gross production will be achieved there?

I'll take that one, having just been to Azerbaijan myself, as you know.

Shah Deniz, very close indeed now.

It will be this year, and it could be very soon indeed.

So, very close on that one.

As far as Atlantis is concerned, we've provided an update there in terms of timing; middle of 2007 is what we said.

As with any project, we'd expect a sort of progressive ramp up towards the full project capacity.

So, a build in Atlantis.

I can't give you individual numbers; it just depends on how the operation goes, and there are many weather uncertainties, amongst others.

But startup of Atlantis by the middle of 2007.

Thanks, Fergus.

Can I just clarify, maybe roughly, are we talking a quarter ramp up or a year ramp up?

Is it unusually large -- unusually lengthy at the time of ramp up in light of the supply issues?

We don't provide specific guidance on that.

It's still a long ways until the second half of 2007.

And it would be best to wait until we get a little closer to the date where very specific programs can be described in more detail.

Neil McMahon, Bernstein.

Two things.

First of all, just looking at your exploration write-offs associated with exploration expenditure in the quarter, that's gone up dramatically.

I presume that's a combination of two things -- one, a few unsuccessful wells, plus increased exploration costs.

Could you give us an insight in terms of what that was specifically due to, and potentially if Sakhalin, and new drilling in Sakhalin was involved there?

And I've got a follow-up as well.

You're correct that there were several wells that we decided to write off over the course of the third quarter.

We don't provide specific details.

We never have.

I know that you're curious to know the geography on that, but I'm sorry; we can't help you on that at this time.

As a follow-up we'll give it another go on something else.

The Whiting refinery -- could you just go through your strategy in upgrading that?

Obviously, recent deals, especially with some competitors, has linked into the upstream side of the business.

As you don't have an upstream side to the business in Canadian oil sands, maybe if you could just walk us through your strategy, and how you're going to seek out partners going forward.

The value of the heavy oil in Canada is directly related to the capability of the refiner to process it; therefore, the real values sits in having access to the facilities.

We believe our upper-tier refineries at Whiting and Toledo, which already process a considerable amount of heavy Canadian crude, are as well positioned as any refineries in the United States to expand that capability.

We're putting in place long-term supply contracts, which allow us access to that crude oil at what we believe are favorable terms.

And we, as a consequence of having the processing equipment, don't feel as though realizing substantial value from Canadian heavy crude oil is necessarily -- one doesn't necessarily have to invest directly in the upstream in order to realize the significant value associated with the processing equipment.

Any idea when you're going to give us guidance on those upstream agreements, or supply agreements?

We don't normally provide detailed descriptions of such agreements, so the answer is I doubt if we will be providing those.

Mark Gilman, Benchmark.

A couple of things, if I could.

Back to TNK for just a minute.

Exclusive of the (indiscernible) gain, and taking into consideration, Byron and Fergus, your comments regarding the product and crude export mix, the result looks very strong to me.

And thus, I was wondering what, if anything else, might be influencing that figure.

Secondly, Byron, if you could put a number on the IFRS effect in refining and marketing, I'd very much appreciate it.

Third and finally, on Alaska, can you give us some guidance as to both an updated cost estimate for the replacement of the gathering lines, and what the production impact in 2007 will be of that project?

That's a wide-ranging set of questions. (multiple speakers) in TNK-BP in the third quarter -- it was a quarter when there was very high prices in Russia.

There was -- I'm just trying to decide what of the many factors here to share with you.

If you strip out the gain on sale, and you strip out the tax lag effects that Fergus was referencing earlier, I don't think there's anything unusual, except the fact that normally in the summertime there are greater abilities to realize profitability through our TNK-BP venture.

It's typically when domestic prices are at their strongest.

And we're one -- because one can use the full variety of transportation options, is able to most effectively optimize the lighter integrated system, remembering that TNK-BP is not just about production; it's about production and refining and marketing assets.

And you'll have noted, Mark, in the release that the Russian domestic price did stay slightly stronger than usual, actually, over the summer.

So that, obviously, helped.

Fergus, you want to cover IFRS?

Yes.

IFRS in Refining & Marketing, Mark -- as you know, this is a source of volatility.

It was particularly volatile in the fourth quarter of '05, and it's comeback in a positive way in the third quarter of 2006.

You're looking at a number in the order of 400 to $500 million.

Is that absolute or a delta, Fergus?

I'm sorry;

I didn't hear you.

As Alaska goes, there will be no -- there, obviously, is cost associated with the replacement of these lines.

That cost is modest as far as a BP share goes, and it should have no impact on 2007 production.

[Colin Smith], DKW.

Just on Texas City again, my perception is that startup does seem to be taking a little bit longer than originally dated.

Can you take us through the key steps that have to take place now, and perhaps give us a little bit better visibility on what the phasing of the return to full production might look like?

And secondly, can you just give us an update, if there is one to be given, on how things are going on the Coryton disposal?

Let me talk about Coryton first.

We announced a few months ago that it was our plan to dispose of that, that it was a refinery that we no longer felt was strategically required within the BP system.

We have taken it out.

We are in the process of receiving in bids for the facility.

We will need to evaluate them.

And in due course, not necessarily this quarter, but some time over the next several months, we would probably be in a position to make an announcement about the sale of the refinery.

But it's going along on track, and we would expect to announce a sale in due course.

On the Texas City subject, given there's some interest in this, perhaps it would be worth just sort of reviewing some of the events, and then looking forward, so that you can understand what has been going on at the refinery since it was shut down at the end of third quarter '05 in the face of Hurricane Rita.

If you remember, that hurricane caused a loss of steam and power at the refinery.

And then through the whole period to the end of the first quarter this year, the site was working to understand the extent of the hurricane damage and the loss of power.

This was the first cold shutdown the refinery had had in more than 40 years of operation.

Production then restarted at the end of the first quarter.

And through the second and third quarter, they've been processing an average of 220,000 barrels a day.

The great point here is safety and smoothness in terms of startup.

It's been very satisfactory in that respect so far, but the real focus, obviously, is on maintaining that quality of operation in terms of safety and operational integrity.

We've seen additional processing facilities commissioned in the second quarter and the third quarter.

We expect further upgrading [plans] to be brought on stream in the fourth quarter.

The remainder of the refinery is expected to be brought back on stream in a phased manner throughout 2007, as I said, with the focus remaining on the safe and reliable startup.

We do see additional sour crude processing facilities re-streaming in the first half of next year.

That will allow more high-sulfur crude to be processed.

That will, obviously, help the profitability.

We should be at over 400,000 barrels a day crude rate before the end of '07.

So, to give you a sense of the scale of what's been done, we're talking 10 million man hours to date on the site commissioning; we're talking about the refurbishment and safe startup of a 27-mile-long steam system; we're talking about mechanical renovation across the site; removal of blow-down stacks; [installation] of the new flare system; new buildings; a new state-of-the-art command center.

There's a huge amount of work going on there.

So, I think you'll understand that the safety and operation integrity aspect has to be paramount during the restart.

And there is a huge amount of work going on there.

And the schedule does show it back better, actually, than it was before the shutdown, towards the end of next year.

That's helpful.

Could you just talk us through what, if you like, the next major two units are, and some idea of when they come on, or at least which ones we're still waiting for startup on?

I think I'll come back to you later.

Aromatics production restarted in late August; the [toluene] unit October; butane split in November; clean diesel December; gas oil [hydra] (indiscernible) December.

It's happening all the time.

It's a very complex refinery, as you know.

So, every couple of weeks a new unit is being restarted.

So, it's progressive.

But you will see, I think, each quarter showing progress relative to the prior quarter, and particularly against the prior year, through the next 12 or 15 months.

The incremental processing units don't really change the amount of throughput, but allow the refinery to make additional high-value products.

The big increment will occur when the next crude unit is brought in into operation.

Fergus said it, but I would like to just reiterate it again.

There is no timetable for this refinery being back to full financial operation.

We're progressing it consistent with the fact that we have to have a safe, environmentally responsible, but most important, process safety orientation to each step that we take there.

I was down in Texas City myself a couple of months ago.

I had a chance to meet with the wider team there, go out and meet with workers on the site.

And I was struck by the enthusiasm that the employees have of making that refinery the best refinery anywhere.

And they're going to make sure that as they go through the process, they don't stumble at any stage.

That's an orientation that you see not only at Texas City; you see at all the refineries and all of our process operations around the world.

Jack Aydin, KeyBanc Capital.

Could you break down the R&M for -- what percentage was -- what portion was R and what portion was M?

It's about 50/50, Jack, R and M. But you have to recognize that there was a large, asymmetric accounting benefit that occurred in the third quarter in R&M, and the bulk of that would sit on the refining side.

So, stripping that out, considerably greater contribution from marketing this quarter than from refining.

So, if you take the 4 to 500 million of IFRS out, so it then will be much higher?

If you strip that out, it's more like two-thirds, one-third (multiple speakers) marketing, one-third refining, if you strip that out.

Jon Rigby, UBS.

A couple questions.

First is -- I saw the tax movement cash over P&L charge was fairly adverse this quarter.

Are you saying in your projection for the gearing to the end of the year that you think again it will be quite a high cash tax out in the fourth quarter maybe?

Can you quantify that?

And secondly, just for my own satisfaction, can you just walk me through what gets us from the original guidance for the year of 4.1 to 4.2 million barrels a day to the 3.95 on sort of annual per-barrel basis, the sort of key components of that movement?

Thanks.

I'll answer the tax -- the fourth-quarter gearing question, and start on the second one.

And then Fergus will add some additional color to that.

The fourth quarter of each year is a time when we experience a number of things.

It's seasonally one of the higher tax -- cash tax payment periods, as your indicating.

But more importantly, our capital spending tends to be more heavily concentrated later in the year, in particular in the fourth quarter.

And we have seasonal working capital swings in a number of different geographic locations.

And the combination of all that in each fourth quarter creates a significant jump-up in our net debt and, therefore, our gearing ratio.

If you look back over history, you will have seen this.

The last quarter in which we were back in our range was in the fourth quarter of 2004.

The only reason we weren't there in the fourth quarter of 2005 was because we received the large proceeds from Innovene, which we have been returning to shareholders over the course of 2006 in the form of share buybacks.

I'm going to come at it one way, and Fergus will, as I said, probably add some additional color to it.

If I go back to the 4.1 to 4.2, remember that was -- the guidance that we gave in February was in the context of -- excluding any divestments that would occur in the course of 2006, and based on a $40 price projection.

If we adjust for the prices that we have realized year-to-date and extend that through the fourth quarter, and we adjust for the divestments that have occurred over the course of the year, then the combination of those two are about 115,000 barrels per day.

So, relative to our guidance, one would deduct 115,000 barrels a day, just from those two effects.

Now, recognizing that 3.95 is slightly less than that, I'll give it to Fergus to finish closing the gap.

You'll remember the guidance that we gave in the second quarter, that the effect of the oil price being higher than the $40 guidance that we used to set the range of 4.1 to 4.2 back in February would be worth 45,000 barrels a day.

And as Byron said, the divestment effect has been creeping up through the year as we've seen value in more divestments and we've executed those divestments.

So, there's about 70,000 -- gone up a little bit over the last three months -- of divestment effect.

So, you take the prize effect of 45,000 barrels a day, you take the divestment effect of 70, and it brings you down to 3.990 or something, the bottom-end of the range, up to 4.090.

And the projection we've given you is 3.950.

So, we are 40,000 barrels a day below the bottom-end of the range.

And most of that, actually, is Alaska; about 25,000 barrels a day full-year effect from the operational integrity issues in Alaska.

There's been some greater downtime in the North Sea as well.

So, those are the main moving parts; most important, divestments and price, but that has some operational integrity effect as well.

Is the operational integrity effect the gap between the 4.1 and 4.2 that you had in the original projection sort of (indiscernible) effect?

(inaudible) drive to increase the capacity utilization of our upstream hardware.

We have talked about that in terms of having objectives, particularly in the North Sea, where the number is quite low, to get it up.

Now, a lot of work is going into making that happen, but it hasn't happened in 2006.

I think it is an opportunity for 2007 and beyond.

And one of the reasons why we have had these prolonged maintenance seasons in the North Sea in both '05 and '06 is an effort to do the work that will allow that to happen.

So, we're taking the pain at the moment, but we're hopeful that it will bear dividends in the future, in terms of giving us greater operational reliability in future years.

Dan Barcelo, Banc of America.

You mentioned the awarding of licenses in India and Pakistan.

As this is not one of your profit centers, could you discuss your strategy in this area a bit, and also the type of resource potential, and then also strategies downstream here?

Thank you.

The two locations that you mentioned have not historically been part of BP's upstream focus, although we've had our eye on the areas for some time.

We do have an upstream position in Pakistan at the current time; a position that we inherited at the time of the ARCO acquisition that has served us well over a number of years.

But consistent with our long-term upstream strategy, we look at basins around the world, we make certain that any place that we would enter has substantial resource potential; it's a place where we believe we can develop a leadership position, and that it's one that will have legs.

Both of these appear to us to have that capability.

In each case we're bringing specific strengths that BP has in deepwater or in coalbed methane to play in a new geography where we believe that our insights and experience will benefit us and the countries involved.

Jason Kenney, ING.

Just following up on the volume guidance, 3.95.

I wondered if you had a split, oil liquids versus gas, for that figure for the full year.

And secondly, maybe a bit of a difficult question to answer, but most analysts forecast figures on the basis of clean numbers, excluding the non-operating items.

Because it's not easy to forecast, especially the extraordinary items.

But the press, obviously, have a headache with this.

So, you do get quite a lot of confusion as to whether the numbers are higher than last year or lower than last year, whether they are higher than estimates or lower than estimates.

I'm just wondering if there is a better way to give guidance on underlying impacts from BP.

Maybe it's one for the future -- but Q3 '07, it's obviously going to be year-on-year quite difficult to interpret this as Q3 '06.

On an NOI basis, fine, but there are underlying effects that are going to be quite volatile here.

Is there anything that you can give us to help us on that?

Let me answer that question.

First, with respect to the volume guidance, we're happy to provide a general guidance for the year.

But we're not prepared at this time to break that down into oil and gas segments.

But you should be able to come up with something very reasonable, just based on the historical trends of the swing, and to higher gas offtake in the fourth quarter versus in the third.

Speakers)

That's what I was angling for.

As far as helping investors out and trying to categorize the volatility that exists under IFRS into various components, I'll just take a second to outline what we've tried to do.

There's no doubt that IFRS has created more volatility in our trading results.

It's created it in everybody's trading results.

But, in ours in particular, it's made them more volatile.

We have over a number of years looked at the categorization of things that we now refer to as nonoperated items.

And we have a very tight control framework around that to ensure that only those items are included in it.

The items that we have decided to identify as such are those items which generally would have material impacts on our annual results, that would swing our annual results around considerably year-to-year, and we think are best categorized separately and looked at in that context.

The things beyond that -- and if we go back to my remarks, we've included $1.2 billion worth of post-tax items in non-operating, and we've included another $1 billion of items that we said relate to volatile items which have appeared in the third quarter.

Those items tend to be ones that are noisy quarter-to-quarter, but, over the course of the year, would tend to net out.

The asymmetric effects or the IFRS effects that we talk about in Gas, Power & Renewables and Refining & Marketing, the consolidation adjustment -- these are things that, one would assume over the course of the year, would certainly not be material in the context of BP.

We've got some other items that we are -- that we clearly identified, but we've not called them non-operating because they sit in associate companies, in particular the TNK-BP gain on sale.

To take items that are treated differently in IFRS, and pull that out, and categorize it as a non-operating item, as we've looked through the mapping that we require in our accounts, we decided it adds too much complexity and is more likely to be confusing than illuminating.

So with that and other items, what we're trying to do is, for the most part, provide you either a very clear indication of the size of it, which you can put into your models or not, or where we're not willing to provide specific numeric indicators, to at least provide you general trend indicators, so you know whether it's up or down, whether it's substantial or minimal.

And we think from that we can provide you and all the rest of our investors good guidance as to what's actually occurring, because we've been very upfront and indicated that we do believe that there are $1 billion post-tax worth of special factors which are impacting the third-quarter results.

But you can then add them into your models as you see fit, and strip them back out again as you see fit when you're looking at 3Q on 3Q in 2007.

I'm just wondering if it's worth adding a clean number on the front page of your results as viewed by BP.

Because a lot of the information you're trying to get across is carried by news wires that just don't understand the complexities of non-operating items or special items or extraordinaries, or things in the numbers.

The clean item is -- the item that we would like to project as clean is that that is -- is excluding or adjusting for non-operating items, and it is the second point that is on our press release.

The first one says what the replacement cost profit was, and the second one says what the non-operating items were.

So, I think we're being very clear on our guidance.

We don't plan to add additional commentary around the quarterly factors, which do net out over the course of the year.

Let me take a question from the Internet.

This is from [Neil Morton] of The Man Group.

The question is -- apart from taxes paid, could you shed some light on the large increase in working capital in the third quarter, expecting that the sharp fall in oil prices in Q3 might have had a working capital release?

If I reference you to page 17 on the stock exchange announcement, that's what looks at working capital.

And the working capital and other movements include tax, so the $6.7 billion number becomes about $1.9 billion of working capital build in the quarter, making that adjustment.

One of the things under IFRS is that there are a number of non-cash items which work their way into working capital movement.

So, the consolidation adjustment, which is a non-cash item, finds its way into inventories.

And all of the asymmetric accounting effects that we have talked about find their way into receivables and payables, as indeed does the charge or credit for embedded derivatives.

There's about $1.4 billion worth of what I'll term non-cash items that are showing through in working capital movements.

And If you adjust for that, that pretty much explains all of the change in working capital quarter-on-quarter.

And I would -- as far as the fall in oil prices in Q3, there is a lag effect on realizing the benefit of -- either a benefit of a fall in prices, or the additional working capital build for an increase in prices.

So, one needs to look back more like 30, 45 days, as opposed to looking at the specific day at the end of the quarter.

And if you do that, then there really wasn't much change in price quarter on quarter.

So, I think the combination of the non-cash elements and adjusting for the timing of price changes fully explains why working capital has moved the way it has in the third quarter.

Ron Oster, A.G. Edwards.

A quick question on your exploration program.

There's been a lot of press here in the U.S. regarding the lower tertiary play in the Gulf of Mexico.

I was just wondering if you could outline your follow-up drilling plans at your Kaskida discovery, as well as your other discoveries there.

Secondly, if you could also highlight any of your key upcoming prospects to look for in this trend, in terms of the timing and the reserve potential at those prospects.

You're asking for some very specific proprietary information there, Ron.

I'm not able to answer that question.

(inaudible) Ron, I guess, that we're pretty excited, which is one of the reasons why we are quite guarded in terms of how much we want to say about it right now.

Secondly, several of your competitors have recently increased their presence in the unconventional oil plays, notably the Canadian oil sands, an area where you're notably absent.

I was just wondering if you could give us your outlook and your longer-term outlook for the Canadian oil sands and unconventionals in general?

We are involved in a number of what people can call unconventionals -- tight sands; we are involved in some viscous oil production in Alaska; we're involved in heavy oil production in Venezuela in Cerro Negro.

So, we do have, both in the gas and the oil side, involvement in nonconventional plays.

But as far as the oil sands, the heavy oil deposits in Canada, go, my answer to the question about Whiting sums it up -- that we believe that we are able to realize substantial value from just owning the processing equipment and signing contracts for accessing new oil, and therefore, do not need to participate directly in the production side.

Peter Hutton, NCB.

A request for a couple of clarifications on comments to answers given two or three ago.

Byron, you mentioned the divestment proceeds from Innovene in the fourth quarter of '05, which you have been returning to shareholders during this year.

The question is, is that right?

Remember from the strategy your guidance on returns are 65 billion paid through dividends and share buybacks '06 through '08 -- I think, $60.

We've been ahead of that.

We've been ahead of the 2.7 refining margin on which that was based.

So, on an annual rate we've seen so far of 24 billion, multiply that by three, yes; you're ahead by 10 against that 65.

But I think a number of people would have thought that a good deal of that increment was because the oil price was higher and the refining margin was higher if Henry Hub was about the same.

Could I just clarify on how much of that 9.5 proceeds from Innovene you think have been paid back this year, and how long that's going to go on?

The other clarification is for you, Fergus, on the production volumes.

On this bridge from 4.1 to 4.2, down to 3.950, we got to 3.990 on the PSA and divestments.

And you said most of that differential of 40, remaining 40, was due to Alaska.

Now, that 40 is on an annualized effect.

Alaska, I thought, was 27 in Q3.

So, on an annualized basis, I would have thought it was quite a bit smaller than that, because it didn't impact the first half of this year.

So, there seems to me to be more like 30 still to explain; maybe I just misunderstood.

Let me deal with the distribution first; then Fergus will respond.

The cash that we use to buy back shares doesn't have a tag as to what it's source is, as whether it's coming from proceeds from divestments or operating cash flow, so therefore, I can't tell you specifically how many of the dollars were from the Innovene disposal.

But we outlined the buyback program in February with the knowledge that we had the proceeds from the Innovene sale.

As you said, in a $60 environment, with particular gas prices and refining margins, that led to distributions over a three-year period of more than $60 billion. $18 billion -- the fact is, with the closed period buyback program, we've distributed close to $20 billion, as we're talking on the phone today.

So, I think we are on track with respect to fulfilling the financial framework and cash distribution guidance that we gave you back in February.

So, the 65 included (multiple speakers)

(multiple speakers) was Alaskan operational integrity issues; not just the events of August.

You'll remember in March there was a spill that also involved some loss of production.

So, there have been a series of events in Alaska this year which in aggregate have had an impact of about 25,000 barrels a day.

I didn't mean to -- I'm sorry if I implied that;

I was only referring to August.

I didn't mean to do that.

It's 2006 as a whole that I was talking about.

Just so I understand -- so, the financial framework, the 65 billion over three years at 60, that included the benefits of the Innovene disposal?

That included the benefits of the Innovene disposal, which was cash we had on hand at the time we gave the guidance.

And it presumed divestments of about $3 billion a year, consistent with the longer-term framework that we outlined for you at the time.

[Stefan Fucoh], [SG].

I have two questions.

First, the crude and liquid [relation] price, possibly in U.S. and for the rest of the world compared to last quarter and last year, seems to have gone up significantly more then Brent or WTI.

Could you perhaps please come back to the reason for this discrepancy?

And second, am I right to assume that the new Alaska production tax represents a recurring charge of about $150 million per quarter?

I can confirm your second question; about $150 million per quarter indeed.

So, we saw approximately $300 million in the third quarter, since it was effective from the first of April; therefore, two quarters collapsed into the charge in the third quarter.

Fergus, can you --?

Stefan, you're quite right; there are some interesting effects on realizations in the quarter.

On the oil side, realizations did increase very slightly more than the global marker as a result of movements in the U.S., where the pricing is based on a [length] basis, WTI.

Against that, UK, as I mentioned earlier, and rest-of-Europe realizations were slightly lower, and that reflected timing of liftings.

So, it's really -- and then on GAAP, as you know, it's through the regional markers and markets.

And they don't accurately track the markers, to a much lesser extent than in oil.

So, it's a mixture of timing differences and differentials in terms of liftings, and differentials in terms of the movements of natural crudes we're selling and gas that we're selling relative to the marker that we use.

Very finally, Paul Spedding asked the question, to save his overtaxed memory, what was the Russian tax lag effect in the fourth quarter of 2005?

And from my memory, Paul, that was about $270 million.

Thank you very much, indeed, for listening, everybody.

We would be delighted to take any further questions you have through the investor relations team, either in London or in New York.