英國石油 (BP) 2005 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 2005 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 just like to draw your attention to two items.

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

Those of you on our distribution list should have already received them by E-Mail.

If you would like to be placed on a list of future releases, please do let us know.

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.

As you know, this has been an eventful third quarter for the industry and for BP.

In BP's case, as the quarter began, we were working to address operating issues at our Texas City refinery.

We were also entering an unusually active maintenance season in the North Sea and Alaska, while continuing work to ramp-up production for major new upstream projects, including several in the Gulf of Mexico.

Against this backdrop, hurricanes Katrina and Rita had a material impact on industry prices and margins, as well as on BP's operating and financial results.

I will do my best to describe our quarterly results in the light of these events and their impact on the rest of the year.

Following my prepared remarks, Fergus and I will be happy to address your questions.

These charts show our average well and gas realizations and indicator refining margin during the quarter against the backdrop of recent history.

The pricing margin environment in 3Q was unusually volatile.

We entered the third quarter with oil and gas prices and refining margins at or near their historic highs.

This was driven by strong economic growth, general concern over the security of supplies, and increasing reliance on heavier crudes to meet growing market demand.

There was little spare production capacity to accommodate the upsets that occurred during 3Q.

Therefore, interruptions, such as those in the Gulf of Mexico, increase short-term volatility, although the industry successfully maintained supplies to meet demand.

In the third quarter, our average crude oil realization approached $57 per barrel.

This was up 44% compared with a year earlier, and more than $9 higher than in the second quarter.

There's a similar picture in gas.

Our worldwide gas realization was $4.75 per thousand cubic feet in the third quarter, up 30% compared with a year earlier.

The increase in the Henry Hub index was more substantial, as gas moved to parity with lighter distillates following hurricane Rita.

In refining, our indicator margin exceeded $12 per barrel in the third quarter, on the back of industry supply interruptions.

This was almost twice the 3Q '04 level.

Our own refining margin increased less than the indicator margin in 3Q, due to yield differences.

Our retail business operated a loss in the third quarter, and our other marketing activities experienced margin declines.

Olefins and Derivatives margins were around 40% lower than a year earlier.

This type of compression in marketing and petrochemicals margins was not unexpected in a quarter where both crude and wholesale product prices rose sharply.

The first weeks of the fourth quarter have seen some easing in gasoline wholesale prices, and marketing margins have started to recover.

However, significant uncertainty exists and the outlook for marketing margins remains highly volatile.

Our third-quarter replacement cost profit of $4.4 billion was 16% higher than in the third quarter of 2004.

On a per share basis, the increase was 20%, reflecting the benefit of share buybacks over the past year.

Our profit, including inventory gains and losses of $6.5 billion, was up 34% or 38% per share.

These figures include nonoperating items, which I'll describe in a moment.

Excluding nonoperating items, our underlying replacement cost profit was $5.3 billion, up 27% in absolute terms or 32% per share compared with the third quarter of last year.

Operating cash flow rose 5% compared with a year ago, to $6.4 billion.

A year-on-year comparison in 3Q was impacted by phasing of dividends from TNK-BP, as well as higher working capital build related to higher prices.

The $08.925 per share dividend announced today, which will be paid in December, is up 26% compared with a year ago.

The sterling dividend is up 29% year-on-year, reflecting the strengthening of the dollar over the past year.

Our year-to-date results at the bottom of this slide are records for the Company.

These include replacement cost profit of $14.9 billion, up 25%; profit including inventory gains and losses of $18.7 billion, up 33%; and operating cash flow of $22.5 billion, up 23%.

Our third-quarter earnings included a post tax charge of $921 million for nonoperating items.

The pretax charge was $1.255 billion.

There are two main components.

Firstly, our review of environmental and other provisions, which we conduct annually in the third quarter, resulted in a charge of $430 million pretax.

This was slightly lower than in 3Q '04.

Secondly, we have recognized a loss of $724 million pretax on the pending sale of Innovene.

This chart shows the main elements driving the 25% improvement in our year-to-date replacement cost profit, from $11.9 billion last year to this year's record $14.9 billion.

Nonoperating items varied by $1.4 billion, from a gain of nearly $200 million in the first three quarters of last year to a net charge of $1.2 billion this year.

Higher prices in margins added 5.3 billion dollars year-on-year.

More than 80% of this relates to higher oil & gas prices, and the balance reflects higher refining and petrochemicals margins, partly offset by lower margins in our retail fuels businesses.

Acquisition and divestment activity decreased our year-to-date result by $150 million.

This mainly relates to last year's sales of nonstrategic assets in our exploration and production segment.

The $300 million year-on-year impact of higher depreciation, depletion and amortization was also mainly in ENP.

Much of this relates to the production ramp-up from higher margin fields in our new profit centers.

Other factors showed a $500 million year-on-year decrease.

The most significant driver was hurricane-related impacts.

We also completed more extensive seasonal maintenance programs in the North Sea and Alaska this year.

Partly offsetting these items, we are seeing production gains from new projects, significantly stronger supply optimization benefits, and higher gas marketing results.

Excluding the impact of the Innovene impairment, our effective tax rate was 34% in 3Q.

This reflects a 1% increase in our expected effective tax rate on continuing operations for the year, from 32 to 33%, as a consequence of higher prices.

As I described in July, this year's effective tax rate includes benefits from tax settlements and restructuring, which allowed the release of prior provisions.

Our marginal tax rate is about 40%, which in this year's very strong price and margin environment would indicate an underlying tax rate of around 35%.

Other factors being equal, we'd expect our rate to increase towards this level next year under similar market conditions.

These charts show the year-on-year improvement in third-quarter pretax results for our exploration and production and refining and marketing segments.

Hurricanes Katrina and Rita impacted both segments.

These were two of the most destructive storms of recent times, in what has been the most active hurricane season in more than 70 years.

We estimate the 3Q impact of these storms on BP at $700 million, $550 million in E&P and $150 million in R&M.

This includes foregone volumes at prevailing prices and margins, as well as direct response and repair costs.

Our exploration and production results increased 36% to $6.5 billion.

Production declined by around 2% between periods, due to hurricane impacts and higher seasonal maintenance, primarily in the North Sea.

BP shut-in production amounted to a quarterly average of about 135,000 barrels per day in 3Q.

Looking ahead, we estimate that hurricane impacts will reduce fourth-quarter production by around 160,000 barrels of oil equivalent per day, although the exact amount depends on the restoration of industry pipeline capacity in the Gulf of Mexico and, to a lesser extent, the completion of repairs to BP and partner-operated production facilities.

We expect all of our deep water fields to be back on stream by the end of the year, with the exception of the shell-operated Mars platform.

As I indicated at the time of the second-quarter results, I will now give you an update on Thunder Horse.

We stabilized the facility and restored it to normal trim during July, and it has successfully weathered both hurricane Katrina and hurricane Rita.

BP has thoroughly investigated the incident.

We have concluded that it was not storm-related, but was caused by design weaknesses in the ballast system, which can be corrected offshore.

We now expect Thunder Horse to begin production in the second half of 2006.

We incurred costs of more than $100 million in the third quarter to secure and repair the Thunder Horse facility, and we estimate our total cost will be around $250 million.

We will expense this as the work gets completed.

TNK-BP contributed over $800 million to our Q3 results, $275 million more than last year.

This reflects higher prices and the continued benefit of the like calculation of export duties in a rising market.

Shifting now to refining and marketing, our result of $1.9 billion was 41% higher than the third quarter of last year.

Stronger margins and supply optimization benefits more than offset the impact of compressed retail margins and lower refining availability.

Despite outages in major industry pipelines due to the hurricanes, our logistic teams kept our customers supplied throughout the period.

Like other refineries in the area, our Texas City facility was shut down as hurricane Rita approached.

We are now working to complete the safe restart of the refinery.

We expect this to occur around year-end and to reach pre-hurricane rates in 1Q.

Our gas power renewables result exceeded $300 million, compared with $30 million in the third quarter of last year.

The 2005 figure includes an IFRS mark-to-market accounting gain for imbedded derivatives of around $90 million, which we classify as a nonoperating item.

The main source of operating improvement was stronger performance in our North American gas marketing business.

In other business and corporate, or OB&C, we reported a third-quarter loss of around $450 million, slightly more than last year.

Both periods include a material nonoperating charge related to our annual review of environmental and other provisions.

Excluding nonoperating item, and the contribution from the retained Olefins and Derivatives Asian joint ventures, the cost of corporate activities was within the previously indicated range.

With Gulf of Mexico hurricanes dominating the news in 3Q, it is important not to lose sight of our ongoing strategic progress in other regions.

In July, we saw first oil production from the Kizomba B field off-shore Angola.

This is another major step in building BP's production profile in Angola, where we expect to be producing over 160,000 barrels a day by year-end.

Also in 3Q, we made our seventh and eighth discoveries in the BP-operated Angola Block 31, and we announced our ninth discovery in the block last week.

Our joint venture with Rosneft produced a second discovery off-shore Sakhalin Island in Russia.

We plan to continue exploratory drilling in both areas during 2006.

In early October, we announced plans to double the capacity of the Wamsutter gas field in the U.S.

Rockies by investing $2.2 billion to drill 2,000 wells over the next 15 years.

In September, we announced plans to build a second world-scale PTA plant at our existing Zhuhai site in China, subject to approval from government.

The new plant with a capacity of 900,000 tons a year, will be the first to employ BP's latest generation of PTA technology.

We expect it to be on stream in 2007.

Shortly after the quarter ended, we signed a letter of intent with Hindustan Petroleum Corporation Limited to form a 50/50 joint venture covering the refining and marketing sector in India.

The joint venture's initial plans include construction of a $3 billion refinery, with a capacity of at least 180,000 barrels a day, and establishment of a retail service station network.

Lastly, we announced our decision to sell Innovene as a single $9 billion cash transaction rather than in phases with an initial public offering.

My next slide provides further information on this deal.

We expect the sale of Innovene to be completed early in 2006.

The buyer, INEOS, is a global specialty petrochemicals company based in the UK..

We believe the sale to INEOS provides excellent value for BP, and also removes potential uncertainty and complexity of a phased sale over a number of years.

The net sales proceeds of around $8 billion will increase the free cash flow available for distribution to our shareholders.

As required by IFRS, we have reclassified Innovene as an asset held for sale.

In the third quarter, Innovene generated a post-tax loss of $781 million.

This includes the sale-related impairment charge that I noted earlier, reflecting the difference between the sales price, net of transaction costs, and the current book value.

Further detail can be found in Note 3 of our stock exchange announcement.

Turning from earnings to cash, this slide compares our sources and uses of cash in the first nine months of 2004 and 2005.

Cash in-flows so far this year are over $24 billion, operating cash flow increased to $22.5 billion, and disposals provided a further $2 billion.

Uses of cash remain consistent with our strategic intent.

Organic capital expenditures have exceeded $9 billion, about the same level as last year.

We expect full-year spending to be around $14 billion, lower than previously indicated, due to rephasing of activity, primarily as a consequence of the hurricane.

We have also distributed more than $13.5 billion of cash to investors, via dividends and share buybacks.

Our pretax cash return in the third quarter was around 40%.

This is about the same level as in the first half, and up more than six points compared with the third quarter of last year.

Our net debt ratio ended the third quarter at just below 20%.

In the current price environment, we expect gearing to return to the lower half of our 20 to 30% target band at year-end, in part due to the normal year-end phasing of working capital movements.

These charts compare shareholder distributions for the past three years with those in the first nine months of 2005, shown on a proportionate scale.

As I mentioned earlier, through the first three quarters, we have returned more than $13.5 billion to shareholders via higher dividends and increased share buybacks.

Since the start of the fourth quarter, we have already purchased another $1 billion of shares under our closed period buyback program.

This reflects our ongoing commitment to distribute 100% of all surplus cash flow to investors, other factors being appropriate.

That concludes my review of the results.

We'd now be happy to respond to your questions.

[OPERATOR INSTRUCTIONS]

Thank you, operator.

We're now ready for questions.

We would like to take our first question from Tim Whittaker at Lehman Brothers.

Tim, are you there?

Yes, hello, Fergus.

Firstly on Innovene.

It seems that the profit was lower than had been anticipated at the trading stage.

Can you confirm that?

It won't have an impact on the sales price.

But more important, can you clarify your intentions in terms of use of proceeds?

You've talked about returning proceeds to shareholders.

Can you confirm this will be in the form of a buyback and also can you confirm whether this is in addition to the ongoing buybacks that you've been making do you have some alternative plans?

And secondly, on your slide number seven, you've shown the reconciliation for nine months, and you talk about heavier--hurricanes and heavier maintenance and also new fields and supply optimization.

Could you give those figures for those two boxes for the quarter just past?

Hi, Tim.

This is Byron.

I'll answer the first question, and Fergus will give some illumination to the second, although we think that it is much better to look at this over a period of time as opposed to on 90-day segments, since there is inherently great amount of volatility that occurs.

With respect to the sale of--of Innovene to INEOS, this is a transaction that we have agreed with them.

It's expected to be completed in the early part of 2006.

INEOS has acquired from us the same entity we were planning on taking to market as an IPO, if we had of chosen to progress that path.

So, they have bought the Company as it has been represented in the S1.

So the--the results in the third quarter, the results in the fourth quarter will not impact in any way the proceeds received.

With respect to those proceeds in 2006, as I indicated, they become cash available for distribution to shareholders.

We are very comfortable with the ongoing share buyback program that we are progressing, and would expect to continue that in 2006.

Yes, and, Tim, just to run by that slightly.

Just in terms of the indications we have at the time of the trading update of the profitability of the Olefins and Derivatives business, you're right.

I mean, it turns out to be quite a weak quarter.

The variable contribution margin that we track in that business was only half of Q2's levels, in the third quarter.

So quite a big decline there from $155 a ton down to $75 a ton in the third quarter, and that compares to $128 a ton in the third quarter of 2004.

In terms of the numbers on Slide 7, I think Byron's text actually went through and mentioned most of those numbers, Tim.

The interesting thing is there's a large number of moving parts there, but the net impact is actually relatively smaller, about $500 million.

Probably the best thing is to take that one off-line and go through you in more detail the numbers that Byron gave.

Tim, I may not have fully answered your question with respect to the Innovene proceeds.

Yes, indeed, that $8 billion more cash that we'll have that is surplus to our requirements in 2006.

Therefore, that would be an increment of for, let's say share buybacks, relative to not having progressed the transaction at all.

And have you definitely decided that buybacks the right to do it, or have you considered tender offer or special dividends or some other form?

On an ongoing basis, Tim, but at the current moment, we remain comfortable with the program that we are progressing.

I think, Tim, you know, the hurricane impact, as Byron said, about a $700 million number pretax, that's about $450 million after tax.

Now going to the U.S., we've got Robert Kessler from Simmons and Co. Robert, are you there?

I am here.

Good afternoon.

Question or point of clarification on your Cap Ex guidance now having been reduced to $500 million for '05, noting that '06 is steady with your prior guidance at $15 billion.

Given that you cited the primary variance being the rephasing of the timing associated with hurricanes, why would we not see a corresponding increase to your Cap Ex next year?

Robert, we clearly will have to be regularly reviewing this as we march through the back side of the year.

Much will be dependent upon how quickly we can get back to some of the capital programs that have been impacted in the Gulf of Mexico there, in particular the deep water Gulf of Mexico, and spending next year will be very much dependent upon the rate at which we leave the--the end of the year.

If there are additional storms, if there's additional disruptions to our ability to do things there, that's likely to set us back further.

So one might, in that sort of situation, see spending moving out of '06 and into '07.

It's really too early to be able to properly calibrate that.

We've given you the best estimate that we have at the current time, but we will, as we always do, be providing better guidance on this at that time of our fourth-quarter results in February.

I appreciated the number you gave around the cost of repairs for Thunder Horse.

Do you have a separate number for the amount of Cap Ex left to spend to get that facility up and running?

No, I don't.

Okay.

Thank you very much.

Thank you very much, Robert.

Now coming back to the UK, John Wright from Citigroup.

John, are you there.

Yes, hi, guy.

Just a couple of questions, please.

First of all, in the UK downstream, sharp improvements on Q2, about $300 million.

I wonder if you can talk us through what drove that?

And also, your short-term debt has increased by around four billion from Q2 to Q3.

I wonder if, as well, you could explain that, please?

Yes, I'll start off on the UK downstream number, John, you are quite right, the number excluding operating margins were $271 million from the third quarter '05, which is the largest number you've seen in the UK for some time.

It doesn't reflect the profitability of petrol reselling in the UK, which was in loss, I would say, in the third quarter.

What it does reflect is the movement of product from Europe into the U.S.

You knows, as we mobilized our logistics system to deal with the aftermath of the hurricanes, and that related--that resulted in some supply and trading profitability in Europe, including the UK, but equally losses in the U.S. almost exactly matching.

And you'll note if you look at the regional breakdown of profitability of refining marking in the U.S., that number was really quite low, in fact quite lower than a year ago.

So the UK storm number really is matched by an equal and offsetting amount in the U.S.

John, the--the variations that we have between long-term debt and short-term debt are often just a reflection of the volatility that we end up with on quarter-to-quarter.

We want to put in place an appropriate amount of--of long-term debt to ensure that we're not facing too regular of a turnover of that debt.

But, variations on short-term here, as the overall debt of the Company moves up and down, is normal, and what you saw during the course of the--of the third quarter is within the normal variation that we have across the course of the calendar year.

Is it also the representative of the--some of the bigger working capital moves?

There are clearly needs to be able to--to as adjust as working capital goes up.

That's the reason I spoke to the volatility.

The volatility associated with product prices here means that we will want to be able to respond to that in--in short fashion.

Having a bit more short-term debt to swing as events occur is again consistent with the way in which we manage our debt book, and there is nothing out of the ordinary in third quarter with respect to that.

Thank you.

You should note that the net debt has increased from quarter to quarter, and this--so you would expect the short-term debt has moved up quarter to quarter, corresponding with that.

Okay.

Thanks.

Neil McMahon at Bernstein.

Neil, are you there?

I've got three quick questions, hopefully.

The first one's just on demand.

With the first few weeks of October gone, any indications that--where demand is in terms of gasoline, petrol, diesel and chemicals versus last year, and if high prices are continuing to impact demand?

Secondly, on marketing, as you've been able to successfully sell Innovene, any sort of major strategic moves in terms of selling off the marketing divisions in the mature areas of they appear to be under political fallout when high prices are in the market?

And lastly, any guidance you can give us on the ramp-up timing of Azeri production in '06 and Thunder Horse and Atlantis?

Thanks.

Well, with respect to demand, we--we don't see anything material happening out there.

There's been a lot of speculation that the higher prices would put a break on--on consumption, and although there tend to be anecdotal evidence to support that, when we look at the main figures. we're not seeing any editorial slowdown at all on the--on the demand across the globe.

As far as what we see strategically in our retail business, we continue to invest in that business.

We feel very comfortable with its strategic positioning within the group.

In periods like we saw in the third quarter, retail margins also always come under a great amount of stress.

That was true with our petrochemicals business in the third quarter, as well.

But under more normal times, these businesses provide a good return for the investments in them, and we remain very comfortable with the retail business being part of the group's portfolio.

Moving on to your question, Neil, with the shape the ramp-up in Azeri, Thunder Horse and Atlantis.

Clearly, Azeri has been held back a little bit as exposed by the pace of line fill, but as we move towards the shipments and first cargos from the Ceyhan Terminal in the early part of next year, we expect that to move to the net to BP plateau rate of 250,000 barrels a day and then, of course, we'll start to move to the second and third phase of that project.

As far as Thunder Horse is concerned, it really--if the question relates to 2006, depends on your assumed timing.

If the Thunder Horse project starts up at the beginning of the first half, if weather is extremely benign in '06, then you could expect to see that build-up over the course of a year toward its plateau rate.

Obviously, if it's toward the end of '06, that process will take place in 2007.

As far as Atlantis is concerned, our expectation remains that that would come on screen toward the end of 2006 and, therefore, we'd expect that build-up to take place during the course of 2007, towards a plateau rate net to BP of 100,000 barrels a day.

So, it's basically an '06 --

Fergus inadvertently said the first half, when he was making his remarks.

It is definitely a second-half start-up for Thunder Horse.

It will definitely depend upon, as Fergus indicated, the state of the weather conditions that we have to deal with in the Gulf of Mexico.

And as he related, if weather is benign, which it hasn't been for some time now, it will allow us to--to get going on it.

But it needs a period of time for people to get out there to progress to work and a series of storms going through will be--be very disruptive.

And we talk about hurricanes.

There's also a phenomenon called loop currents that would tend to also slow down the pace of which we can get the facility online, if they continue to be as difficult in 2006 as they've been during much of 2005.

Once again, very similar to capital spending in 2006, we will give you a better perspective on this as we provide our fourth-quarter results, because by then we'll have had an opportunity to just see how the work is progressing during the fourth quarter and the entry into the new year.

Just a clarify, if we had peaked production from some of these fields, or at least the initial ramp-up phase by mid-2007, that would be a fair assumption allowing for some of the flexibility of when you are going to bring on these--these--these substantial fields?

I think about 12 months is a reasonable expectation, particularly as the Gulf of Mexico builds, and apologies of that slip of the tongue.

Now moving on to John Rigby from UBS.

John, are you there?

I am, thanks.

A question in the UK Are you able to split-out the effect of natural decline rates from interference or problems with maintenance that you've had this year to get an idea of the direction, particularly in liquids, which we've seen, I think, about 15% decline this year on average for first three quarters?

And then following on to that, and I guess very closely related to that, have you, BP, been having discussions with the UK treasury, UK-BTI, about potential changes to TAC legislation North Sea, very much tied into future investments?

I'm--I'll talk to the big picture with respect to not just the North Sea, but I think all of our existing profit centers and Fergus can provide a bit more detail behind that.

It's--it's very difficult to penetrate through all the disruptions that we had in 2005.

Storms in the Gulf of Mexico, some of the--the large amount of turnarounds that we've had in the North North Sea, some operating problems that we've had in various fields there as well, and really look through that and determine whether or not we are on track with the guidance we provided at the start of the year.

But as we go back through and make our adjustments, and we--we spent a lot of time thinking about this, we do believe that we continue to be on track to the guidance that was provided earlier this year, that over the course of a five-year period, that the decline rate in our existing profit centers will average about 3%.

Now as a result of being lower this year, you will see a rates that don't decline at--at next year.

But the underlying trend over the run of years as best we can determine it remains consistent with earlier guidance.

Fergus?

Yes, and just to build on that in terms of your specific questions, John, about the North Sea, and particularly about liquids in the UK There's a decline--I think it's probably best to look at this over the first nine months of the year.

If you look at the first nine months of the year, the decline is around 50,000 barrels a day and about a third of that can be probably be contributed to the heavier maintenance that we saw in the third quarter of 2005.

Most of the rest is natural field decline.

It is the case that the UK North Sea is one of the areas with the highest decline rate amongst our existing profit vendors.

There are new projects under way, as you know, [Ron McClair] to name two, to mitigate that and, equally, many of the other areas within the existing profit vendor portfolio including, for example, Argentina, have got better characteristics, which gives us the overall average decline rate over a five-year period that we expect of around 3%.

So very mixed numbers for different parts of that portfolio.

And are you in the process of trying to educate BTI and the treasury in terms of the kind of tax regime that is needed for mature basin and encourage investment to maintain those kind of production rates?

We have ongoing dialogue with--with the treasury with respect to BP's views, and we also participate in various industry fora in discussions with government.

At the end of the day, her majesty's government needs to decide what sort of regimes that they want to put in place.

But it has been our observation that over the course of time, stable tax regimes draw more investment than those that are regularly adjusted up and down.

Okay.

Thanks.

Moving on to Neil Perry from Morgan Stanley.

Neil, are you there?

Yes, thank you.

Two things.

One is a separate issue from the results, but there's a lot of discussion in the press about your involvement, or potential involvement, in China with Sinopec, and I wonder if you could put any color from your perspective around that?

And secondly, you talked about delaying some of the Cap Ex into next year due to the weather.

Are you also suffering from any tightness in the service sector, inability to get work done or production onstream due to lack of availability in different parts of the service sector at the moment?

With respect to Sinopec, Neil, we don't comment on articles in the FT.

What--what I will say is that we have spent a long time in China.

We have, as a Company, nearly $4 billion invested there.

It is a place where we are very much attracted by the growth of--of the customer-facing businesses.

We have, today, 18 joint ventures with various companies in China, seven of those with either Sinopec or one of its subsidiaries.

And as you heard me say in my remarks, we are progressing an expansion of a current joint venture we have there, the PTA plant in Zhuhai .

So, China is a very much--an important focus for the BP group, as we are attracted not only there but in India, by the growth of demand for our products, as those economies continue to mature.

So I will leave it there.

As I said, I will not speak to the specific article that was in the FT.

As far as--as capability in the services industry, inflation is--we're seeing inflation in a--at levels that are unprecedented.

Tony Hayward and his E&P colleagues estimate it's about 12% across at least the capital component of our business right now.

In the past, we've--we've always been able to mitigate inflation In the sector and we're continuing to do some of that now through technology through long-term contracts we've had in place.

But even with that offset of 2 to 3%, we're seeing 9%, 10% inflation in the sector, and whether this will continue into next year or not, we can only speculate it at the current time.

The industry is running at full capacity, and that's part of the reason why the service sector can--can push things through.

And, in fact, if you look into North America, capacity was actually decreased as a consequence of--of the storm.

Rigs that were providing services are now damaged.

They're--they're on shore, they're getting repaired.

So the--the hurricane-related aspects of this aimed at the most important part of the industry sector out of Houston, and the degree of activity that--that one sees there has certainly put in motion constraints on the sector and has been an important element of the inflation that we're seeing at the current time.

And is that beginning to lead to discussions about project delay, as opposed to just paying a higher price to do the job you wanted to do in the first place?

It--it certainly can have an element of that.

Our rephasing is a consequence of--of the storm-related activity.

We believe that we've lined up the appropriate services to allow our projects to move forward.

But with everything operating at full capacity, it's--it's on a razor's edge here for the whole industry.

Thank you very much.

Mark Iannotti at Merrill Lynch.

Mark, are you there?

Good afternoon, gentlemen.

A couple of questions.

First of all, nonconventionals, nonconventional hydrocarbons has not been near the forefront of your group strategies in E&P.

And does the news that you will make this expansion in Wamsutter, does that signal a change your thinking on nonconventionals, and if so, where--what other areas may you, in fact, be looking at.

And secondly, just come back to Thunder Horse, if I can, can you confirm there won't be a move to recertification of the platform, or is that still potentially an issue up and above the weather issues that you have talked about?

Perhaps I'll have a go at those.

On Thunder Horse, the key point, I think, as Byron mentioned in his prepared remarks that we see the repairs can be carried out offshore, and we have the support of the relevant U.S. regulatory agencies for that indication.

So I hope that answers your question.

Second, on nonconventional.

It should be clear that our position has never been that we're against nonconvision--conventionals, per.

It's just been that we rank our opportunities and make decisions on the allocation of capital.

What other people refer to as nonconventionals, it's not typically made the cut against the other opportunities, which typically most people would clarify--would describe as conventional, we have proceeded with.

Wamsutter is an example, you know, that we are very flexible in our thinking.

It has the return characteristics that we look for.

It has some of the characteristics that you would associate with a nonconventional project in the shape of very low decline rate, very long-lived productive capacity there, some of the wells producing at plateau rate for 25 years already.

And we have many other such opportunities within our portfolio, both in tight gas in United States and elsewhere, and also in viscous oil in Alaska where, as you know, there's a multi-billion barrel resource up there, which due to technology, we're working to see how we can unlock, provided it has return characteristics, which we demand from our investments.

So, hopefully that will give you more of a sense of where we're going on this issue.

We don't think of it in those conventional, nonconventional.

We think of it in terms of what rate of return do we require from these kind of projects.

Mark, I don't we've categorize opportunities like Wamsutter as being something that's outside the bounds of investment opportunities the group would be interested in pursuing.

We see Wamsutter as a very attractive investment opportunity, where technology is continuing to enhance the return characteristics.

Thanks.

Thanks, Mark, good question.

Mark Gillman in the United States.

Mark, are you there?

Yes, I am, guys.

Good afternoon.

I just had a couple quick ones.

First, can you give us a number for the Gulf of Mexico production that shut-in as we speak today?

Secondly, just point of clarification, did you say 230 net to you is a plateau rate for Azeri when BTC is completed ?

That would seem to imply a gross rate of something in the neighborhood of 700, which is above my recollection of Phase 1.

Thirdly, just two things on TNK.

First, the oversized dividend which you received in the third quarter, where are we regarding the releveraging of the balance sheet, which is permitting those oversized payments?

And have there been any changes regarding the split between domestic and--and export, in conjunction with the commitment to hold Russian product prices at constant levels?

Thanks.

Mark, let me talk to the TNK dividend and affairs in--in our TNK-BP joint venture, and then Fergus will pick up the other questions.

The--the dividend, the $750 million dividend that we saw in the--in the third quarter is consistent with--with the cash that the Company is generating at the current time, and is--there is a dividend policy that--that the directors of TNK-BP go through.

The Company, as you suggest works, like does BP, within a gearing band, and the directors on each occasion think in terms of what cash is available, what cash flows they see forthcoming, how can the business manage in lights of the--in light of the uncertainty that exists there in the Russian sector, as well as across the globe as a whole, in our case.

The--the split of domestic versus inner--exports into the International marketplace in the third quarter was--was not materially different than that--that's been the case for a run of quarters.

About 70% of product is exported as--about 70% of production is exported either, as crude or as--as product, and about 30% goes into the domestic market.

Some of it sold as crude oil and some of it refined and sold as product within Russia itself.

One of the big things that--that we saw in the third quarter was the very sharp run-up in--in Russian domestic prices, which, because of the lower tax regime for domestic as opposed to exported barrels, helped contribute substantially to the returns of TNK-BP in the third quarter.

Fergus?

Yes, Mark, coming on to your other questions.

Gulf of Mexico.

The latest information we have for the Gulf of Mexico, as a whole, is that about 66% of normal oil production and 53% of normal gas production is shut in for the province as a whole.

Turning to BP specifically, Byron's given you an indication that we expect a net impact on our fourth-quarter production to be about 160,000 barrels of oil equivalent per day of deferred production.

And the resumption of that production is dependent, of course, on the restoration of infrastructure, particularly internal infrastructure, on the shore.

And it's--it's relatively ratable, but I will get to speak to you offline and take you through more detail on that.

In terms of the Azeri project, there's a series of phases, as you know.

I was referring, I think, to Phases one and two.

Phase three is a further 95,000 barrels a day net to BP.

Of course, the exact amount depends on your price assumption, because it's a production-sharing contract.

But I will, again, come back to you with more details on that offline.

Thanks, guys.

Thank you very much, Mark.

France. [Pascale Mengaz] from [Xane].

Pascale, are you there?

Yes, good afternoon.

Can you hear me?

You're fine.

I have two questions; first is regarding your production profile.

In the second quarter, you provided us with an updated production profile.

I wonder if the announcement you made today on Thunder Horse that just restoring the second semester could add positively or negatively the production profile for 2006?

And my second question is regarding the Cap Ex linked to the JV that you have signed with Hindustan Petroleum Company.

Is the Cap Exyou're showing the Cap Ex going to be incremental to your Cap Ex in the downstream?

Or is it going to be included in your Cap Ex in the downstream?

Well, let me deal with the production profile first.

Clearly, when we were providing guidance earlier this year as--as we were very explicit at that time, we were anticipating that Thunder Horse would begin production at the back side of 2005.

So the delay that's come as a consequence of--of the--of the ballast system problems, as well as the storms and loop currents, et cetera, in the Gulf of Mexico, pushing that back will impact 2006 production.

However, it should not materially impact the longer-term production guidance, because it will come on line and--and produce according to the previous projections that were associated with it.

So in 2006, yes, longer term it would not impact the production guidance that we provided at that time.

As far as the--the joint venture with--with Hindustan Petroleum Company, this is not a deal that is done.

This is still a memorandum of understanding.

It establishes the framework for a deal.

We will be working with them to structure an agreement, and if we are successful on that, then we will build the capital spending into our program.

It is important to remember that this is just the earliest phases of discussions with them, and until the deal is done, we certainly won't be building that capital spending into our forward plans.

Thanks, Pascale.

Moving to the UK, Ed Westlake from CSFB.

Ed, are you there?

Yes, good afternoon, gentlemen.

Coming to that Cap Ex issue, maybe a little further out.

You're saying there are inflation but you're covered by existing contracts, which I guess mitigate the impact.

When you look at the sort of percent are increases, you look out in your model and given $15 billion for '06, plus, minus.

What sort of percentage increase do you think for '07 for the off-stream?

And then just a small question, really, rega--regarding your comments on royalty phasing for BP-TNK.

What benefit did that provide, you know, in the third quarter?

As far as inflation goes, I--I have no idea, nor would anyone, of the pace of inflation as we go into 2006 and 2007.

We--we see the impact of it now, and just to be clear in my comments, I said we were offsetting a portion of that, the same portion that we've been able to offset in--in previous years.

But the overall pace of inflation is such that we're still seeing, not 9% to 10% coming through on--on our capital spending in the sector.

We--we plan on the basis of activity.

We've got an underlying activity set for our E&P operations that we will--will manage, and if--if costs are going up across the sector as a whole, then we'll need to build that in to the--to the projects.

It is something that we'll have a better assessment of, but it will still only be a projection when we talk with you in--in February alongside our fourth-quarter results.

In terms of your question of the lag at the TNK-BP from the rising price in exporting duty, there's just over 100 million in 3Q.

Clearly that will reverse at some point ,but obviously that will require a reversal in the directional movement of hydrocarbon prices, but 100 million in Q3.

Thank you very much.

Gordon Gray at J.P. Morgan.

Gordon, are you there?

Hi, good afternoon, everyone.

A couple of minor questions.

In R&M, firstly, you mentioned that the retail side of the business was negative.

Can you just give us a feel the overall contribution of marketing, including wholesale?

On Innovene, given the sharp fall in income, just a bit of reassurance.

Can you discuss any break-out supply resources to INEOS?

And just confirmation of a number, can you confirm what the Gulf of Mexico hurricane-related outage were--was in 3Q?

In the third quarter--I'll take these questions in reverse order.

In the third quarter, consistent with my remarks, the quarterly average was about 135,000 barrels per day.

With respect to Innovene, we have a contract with INEOS and we remain very comfortable with that contract, and I'll speak to no more details than that.

As far as the overall contribution from marketing, and this includes not only retail marketing but the other parts of the business that we aggregate together when we're--when we're thinking about the marketing business, in totality.

With respect to clean earnings, and that's post-nonoperating items, about 11% of the contribution came from the marketing businesses and 89% from the refining business.

That's great.

Thanks very much.

Just to be very clear, Gordon, the retail was in loss, but the other impairment --

I heard you say that, I was just wondering what the wholesale part of the business.

-- thought the overall number or the number that Byron just indicated.

That's great.

More to the United States. [Nikki] Decker from Bear Stearns.

Nikki, are you there?

Good afternoon, everyone.

On Wamsutter, when can we expect to see the first gas from your new investment?

Nikki, well, of course, the field is already producing.

The--it's incremental investments, that we announced recently, will produce first incremental gas in '06, and that's then building quite strongly to to the plateau rates in the middle of the next decade.

We do, however, have follow-up phases of investment, if we are successful with this Phase one, which would continue to significantly expand the productive capacity of the field, but the Phase one that was recently announce would have its first impact on production from the field in '06.

These are on-shore wells, and we're going to be drilling a lot of them if we progress the full program.

So from --

Sure, understood, and so how --

-- some production coming from --

How do you look at, say, development cost and lifting costs on unit basis?

Can you --

-- although it's a bit more challenging than--than some of the opportunities on-shore the lower 48 in the U.S., it has the same type of characteristics, which you invest and you start seeing production immediately.

Can you -- can you provide some color as to how we would look at development costs and lifting cost on a unit basis, near-term?

From Wamsutter?

Yes.

We can't provide you with that detail right now.

You can talk with Fergus and his team in the I.R. area, and they will provide some additional information.

Yes, the economics, rest assured, Nikki, are extremely attractive, as I indicated in my answer to Mark Iannotti's question, but we'd be more happy to walk you through in more detail offline.

Okay, thanks.

You know, given the timing of the announcement, you know, in this post-hurricane environment, it would--you know, it would appear that it's the high gas prices as sort of prompted the decision, but given the technical studies that needed to be conducted, it--it seems that the decision had been made in a lower price environment.

Can you verify that?

Correct, Nikki.

Yes.

Thanks.

Just lastly, refinery utilization rate --

I don't--I don't believe there are any more questions.

I would just like to --

-- do you have any information on what --

everybody for their attention.

The investor relations team remains ready to answer any follow-up questions you have and thank you for listening to us this afternoon.