英國石油 (BP) 2004 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.

A very good morning to those of you listening in Europe and Asia, and good morning to those in the Americas.

I'd like to welcome you to BP's third quarter 2004 conference call.

My name is Fergus MacLeod, BP's Head of Investor Relations, and joining me today is Byron Grote, our Chief Financial Officer.

Before we start I'd like to draw your attention to 2 items.

First of all, today's call refers to slides that we'll be using during the webcast.

Those of you on our e-mail list should have already received the slides.

We've also sent you a copy of remarks made by John Brown to the UK Press earlier today.

All of these materials are available to download from the Investor Center on our website, bp.com.

If you haven't received this information and would like to be placed on our list for future releases, please do let us know.

Second, I'd like you to draw your attention to the words on this slide.

We may make use of forwarding 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.

I hope you've had a chance to review John Brown's presentation from earlier today, in which he discussed the outlook for oil prices and refining margins, and the inflationary trends in our industry.

I will not repeat his comments in detail, but Fergus and I will be happy to take any questions.

Today we were pleased to announce very strong third quarter results.

Our upstream and refining assets were particularly well positioned to benefit from the price and margin environment during the quarter.

I will summarize the results for the quarter and year to date.

I will also give highlights on our continued strategic progress within the context of our financial framework, as we discussed with you last March.

Our results for the year to date are records for the Company, both in terms of earnings and operating cash flow.

This was largely due to a very strong price and margin environment, which I'll describe momentarily.

However, it's important not to lose sight of this significant strategic progress we have made this year.

Our portfolio of upstream growth projects is on track.

We had several major start-ups in the first 9 months, with more planned for the fourth quarter and into the next several years.

We remain pleased with the progress TNK-BP is making throughout its businesses, as described in TNK-BP's investor presentation last month.

As noted in our trading update, Hurricane Ivan in the US Gulf of Mexico and the Temsah blow-out in Egypt adversely impacted our third quarter volumes.

Based on the anticipated restoration of our Gulf of Mexico volumes, we remain on track to achieve full-year production growth of over 10%, to around 4m barrels of oil equivalent per day, as indicated in our March strategy presentation.

In the customer facing segments we are seeing continued success in margin capture, despite the pressures from rising hydrocarbon prices.

As a result, our pre-tax cash returns are increasing as we capture the benefits of the improved environment.

We continued to generate substantial free cash flow for distribution to our shareholders.

We have used the additional cash to buy back $5.5b of shares in the first 9 months.

The resulting reduction in shares outstanding has allowed us to accelerate growth to improve share dividend, which is up 9%, year on year.

This slide shows upstream realizations and industry margin indicators for the customer facing segments since the beginning of last year.

Focusing on the upstream first, as shown on the left chart, oil realizations continue the upward trend that started last year, averaging nearly $40 in 3Q.

Continued economic growth has driven higher oil demand, particularly in China.

Worldwide oil production has increased in response, as OPEC members have brought much of their surplus capacity online.

But the overall supply demand situation remains tight.

Prices also appear to contain a risk premium stemming from concerns over a variety of security issues that might impact production.

It seems on the basis of the recent track record and the supply-demand balance, oil prices have a support level of around $30 per barrel, at least for the medium term.

Our worldwide average gas realizations remain stable, at around $3.7 per thousand cubic feet.

Prices in the US moved from a premium to parity with residual fuel as the industry rebuilt inventories prior to the winter gazing season.

UK gas prices increased significantly due to the pull from higher oil prices and maintenance activity in the North Sea.

Our overall average hydrocarbon realization is up 33% in the quarter and 17% year-to-date compared with 2003.

As shown on the right, we have also seen solid double-digit growth in industry indicator margins for both refining and petrochemicals.

The chart shows a 3 cube decline of more than 20% in the refining indicator margin compared to the second quarter.

However, margins in our own refineries were similar to Q2.

Much of the incremental volume being brought on by OPEC is getting more heavy and sour, while the majority of the world's refining capacity is designed to take lighter and sweeter mix of crude oil.

Refineries designed to handle heavy and sour crudes, such as the majority of our own, have been able to achieve better than average margins.

In addition, our ability to respond to a quickly changing environment led to a particularly strong supply optimization performance in 3Q.

In contrast to Refining, marketing margins were lower in 3Q than either the prior quarter or the third quarter of last year.

Continued intense competition did not allow us to fully pass through increases in crude and product prices.

Petrochemicals margins continue to improve with the global economy, with both the aromatics and acetyls in the Olefins and Derivatives businesses benefiting.

The strong prices and margins showing here contributed to the record 9-month results we reported this morning.

I'll start with the third quarter data at the top of this slide.

Our 3Q pro forma result of $3.9b was up 43% year on year.

Our replacement cost profit of $3.5b, which includes acquisition amortization, was us 53%.

Our historical cost profit of $4.5b, which includes both acquisition amortization and unrealized inventory gains and losses, was nearly twice last year's level.

Our 3Q adjusted operating cash flow of $6.1b post tax was up 49% year on year.

This includes more than $1b of TNK-BP dividends in the quarter, which partly offset a working capital bill of more than $2b, mainly related to the price increases I described earlier.

On a year to date basis, shown at the bottom of this slide, the pro forma result, replacement cost profit and operating cash flow were all up by broadly similar amounts, around 25%-35%.

Our historical cost profit increased by much more, as it includes more than $2b of unrealized inventory gains this year.

The results just reviewed include a number of gains and losses not directly related to ongoing operations.

These fall into 2 categories.

First, UK GAAP requires us to separately report as exceptional items any gain or loss from disposals or terminations of operations.

You will recall then 1Q these totaled again $1.3b, mainly profits on the sale of our successful investments in PetroChina and Sinopec.

We had a small net gain from exceptional items in 3Q.

We also disclosed material non-operating items in order to help you better understand our underlying results.

So far this year, these items totaled a loss of around $700m post tax.

This amount includes a charge of more than $150m post tax for unrealized profit and stock, which is directly related to rising oil prices.

As I indicated last quarter, and as set out in our trading update, the amounts shown in 3Q 2003 and 3Q 2004 both include charges of around $500m pre tax or $325m post tax, principally related to our annual review of environmental provisions.

Our Stock Exchange announcement provides further details of all these items.

This slide shows BP's pro forma return on capital employed relative to our principle competitors.

The results are shown on a headline basis and include all items that various companies refer to as “exceptionals”, “specials”, “non-operating items” and the like.

These items make earnings, and hence return on capital employed, more volatile.

Notwithstanding this background volatility, our performance remains highly competitive.

Our 3Q return of nearly 20%, although flat with 2Q was impacted by the 3Q environmental charges I just discussed.

This chart shows our pre-tax cash return over the same period.

We explained this measure and its calculation in our strategy presentation in March.

By removing the volatility related to exceptional and non-operating items, tax phasing and price-driven working capital changes, we believe this measure provides a clear view of performance.

Our 36% cash return in 3Q represents continued strong cash generation on the growing capital base.

The data shown are based on actual prices and margins.

The peak in 1Q 2003 as well as a higher level so far this year are driven by strong trading conditions.

After factoring out changes in the business environment, we believe that the underlying trend of cash returns remains one of improvement.

As indicated in March, we expect the underlying return to grow by around 2 percentage points between 2003 and 2006, as we bring additional major upstream projects online.

This chart shows the main elements driving the $2.6b improvement in our year-to-date result, from $10b in 2003 to $12.6b in 2004.

Building from the left, the contribution from exceptional and non-operating items is up $300m over 2003.

Higher prices and margins added another $2.7b to our year-to-date result -- more than half of this from higher oil prices, around 15% from higher gas prices, and around a third from higher refining margins.

We estimate that the impact of the weaker dollar has reduced our year-to-date result by around $350m post tax.

Acquisition and investment activity added nearly $200m to our year-to-date result, with the TNK-BP acquisition more than offsetting the impact of disposals.

Depreciation charges, excluding foreign exchange effects, were up $200m between years on a post-tax basis.

The increase is merely an -- is mainly in Exploration and Production and reflects the change in portfolio composition and the start up of new projects over the past year.

Other factors netted out between years.

Volume growth in new Exploration Production profit centers and the customer facing business, along with lower interest expense, offset production decline in existing E&P profit centers, the impacts of Hurricane Ivan and sector specific inflation.

The Exploration and Production segment remains on track with the strategy reviewed in March.

Third quarter production was impacted by planned turn arounds in Alaska and the North Sea, as well as Hurricane Ivan and the Temsah blow-out.

Hurricane Ivan has impacted our Gulf of Mexico results in 2 ways.

First, the eye of the storm passed directly over several of our major deep-water fields.

We've now repaired the storm damage to these facilities and are ready to resume production.

Secondly, the storm severely damaged several pipelines used by our fields.

Some of these pipelines are still being repaired and tested and have not yet been restored to operation, and thus continue to limit our off-shore production capability.

Nonetheless, we expect 4Q production to increase substantially, driven by completion of seasonal maintenance in the North Sea and Alaska, recovery from Hurricane Ivan and a ramp-up from new fields across the portfolio.

In line with previous statements, we expect full year production to be up by over 10% compared to 2003, at around 4m barrels of oil equivalent per day.

Looking beyond 2004, all our major projects remain on track for delivery and there is no change in the long-term volume expectations we stated in March.

Turning to capital spending -- as I mentioned earlier this year, in the spring we began to see that the market prices for our capital goods were increasing quite strongly.

The increased investment within the global E&P sector has led to a tightening in all our supply markets.

As activity levels rose, unused capacity was absorbed.

Steel prices began to rise significantly, adding further to the overall inflationary pressure in the sector.

As a result, the market price for our mix of capital goods has been rising at a rate of 10% per annum.

Our supply change management -- our supply chain management has offset around half of this.

And we had expected, in any event, to offset 2% during normal activity.

Overall, therefore, we're seeing a 3% increase in our capital costs above the level anticipated in our plans set last year.

In addition, our capital expenditure is not all made in dollars.

When we set our 2004 plan a year ago, the dollar was considerably stronger.

So, the impact of the weaker dollar has increased the dollar-based capital expenditure.

All of this, then, explains why in July we increased our estimate of E&P capital expenditure from $9b to $9.5b for 2004.

We now expect it to be just above this level.

I also said in July that for the Group as a whole capital expenditure for 2004 would be around $14b.

This included an estimated increase of $200m in the capital expenditure of the customer facing segments, again caused by the weaker dollar.

We now estimate that total capital expenditure in 2004 will be just above $14b.

What does all this mean for E&P capital expenditure in 2005?

It's too early to be definitive, but we can make some assumptions to gauge the possible impact of the dollar and sector-specific inflation.

To get the base line, let's assume the dollar holds its current value -- and that maybe a brave assumption -- and that the inflation we've seen between 2003 and 2004 is baked into our expenditure.

Increased activity and appraisal, as a consequence of Exploration success -- that's primarily in the Gulf of Mexico and Angola -- will take our expenditure at the top of the range we talked about last year, that is, $8.5b.

On top of that, we should add $200m for the weaker dollar and $300m for the sector-specific inflation between 2003 and 2004.

The total therefore comes to $9b.

If we see more inflation, this amount will rise.

So if the market price of our mix of capital goods continues to experience inflation at 10% a year, if we succeed in offsetting 2% of the price increase in-line with our long term track record, and if our supply chain management offsets another 2% -- and that's a lower amount than in 2004 because of the maturing of certain contracts -- then the inflation we will actually experience between 2004 and 2005 would amount to around 6%, or about $600m.

In these circumstances, E&P capital expenditure would rise to $9.6b.

There may also be greater than expected inflation in the prices of capital goods used in the customer facing segments.

And their capital expenditure level will also be affected by the strength or weakness of the dollar.

For the Group as a whole, all this means that capital expenditure is expected to be just over $14b in 2004 and could be around $14b in 2005.

Of course, this is based on a number of assumptions, but it is higher than we previously estimated.

Capital expenditure has risen because the dollar is weaker and world demand is up, and that has strengthened the oil price.

Of course, the contribution of the stronger oil price to our capacity for shareholder distributions overwhelms the effect of the increase in capital spending.

Our long term track record of Exploration success continued in 3Q.

In addition to earlier announced discoveries in Angola and Egypt, we had what we believe to be a significant third quarter discovery on the Pela Lache prospect, located offshore Sakhalin Island in Russia.

Turning to Development, all of our 2004 major project start-ups remain on track.

Following In Salah and the Atlas Methanol find in the first half, production began from the fourth LNG train in the northwest shelf of Australia and the Kizomba A field in Angola during the third quarter.

Expected start-ups in the fourth quarter include Holstein in the Gulf of Mexico and Clair in the United Kingdom.

As shown here, our share of TNK-BP net income after the accretion of the discount on deferred shares consideration was $499m in 3Q.

This is up 43% compared with 2Q.

The 3Q increase primarily reflects higher prices and the [right] calculation of export duties in a rising market.

This benefit was partly offset by the new export duty rates that became effective on August 1, 2004, which I described in our last webcast.

It also includes the $25m credit with respect to prior periods.

Urals prices into northwest Europe increased nearly $5 to more than $37 per barrel in 3Q.

Higher export prices and the domestic demand allowed Russian domestic crude prices to strengthen to more than $23 per barrel.

TNK-BP production increased 6% relative 2Q.

Crude and product exports for the quarter were slightly lower, at 65%, as the Company optimizes realizations in the face of the higher export duties.

Dividends received during 3Q totaled over $1b.

This relates to our share of earnings during the fourth quarter of last year and the first 2 quarters of 2004.

TNK-BP has now moved to paying dividends 1 quarter in arrears.

Holding prices and the percentage of exports constant with 3Q levels, we would expect our share of TNK-BP profits in 4Q to be approximately $160m lower post tax than in 3Q.

This reflects the lagged increase in Russian export duties as well as a full quarter under the new export duty rates.

In Refining and Marketing we responded to the fast changing conditions to capture the margins available in the marketplace.

As I mentioned earlier, our strong refining result in 3Q benefited from the widening differentials between light and heavy crudes, as well as active optimization of supplies into our refineries.

In our Marketing businesses we held sales stable in the face of intense competition and compressed margins.

In Retail, customer continue responding very favorably to the BP format in our accelerator markets, both in our shops and with our premium grade Ultimate motor fuels at the pump.

We're now extending these offers into additional markets.

The Gas Car Renewables segment continued to deliver strong volume growth.

Sales volumes in the first 9 months were up 14% for natural gas, up 12% for equity gas into LNG plants, and up 16% for natural gas liquids.

Along with the partners in our Tangguh project in Indonesia, we recently completed long term LNG sales agreements with K Power in South Korea and Sempra from markets in Mexico and the Western US.

Total contracted buy-ins of 7.5m tones per year are now sufficient to support 2 LNG trains.

We expect to review the Tangguh development project for sanction later this year.

To support our growing LNG business, we placed orders for 4 more LNG carriers, which will increase our LNG fleet to 7 ships.

In Petrochemicals, year-to-date production volumes are up 4%.

The increase reflects recent additions to PKA capacity in Asia and sustained higher asset utilization.

We are continuing our work to establish our Olefins and Derivatives business as a separate entity within BP, with a view to disposal, potentially by means of an initial public offering in the second half of next year.

We have identified the top layers of management for the O&D business and are now structuring key operational and commercial interfaces between O&D and the rest of BP.

Other efforts to focus our Petrochemicals portfolio continue.

Shortly after the end of 3Q, we reached agreement to sell our Fabrics and Fibers business.

We expect to complete this transaction before year-end.

Returning to the Group's results, this slide compares our sources and uses of cash for the first 9 months of 2003 and 2004.

Operating cash flow up $18.7 before pension funding was up more than $3b, year on year, as I noted earlier, a record for the Company.

The China share sales and other disposals have added $4.2b after tax, bringing total sources to nearly $23b.

We've reinvested nearly $10b of this cash back into the businesses as organic CapEx.

Shareholder distributions have also totaled £10b -- $4.5b of dividends and $5.5b of buy-backs.

This is an increase of more than 60% compared with the same period of last year.

Total cash sources also have exceeded uses by $1.6b year to date.

This has resulted in lower net debt.

As shown here, gearing has remained in the 22 to 23% range for the past 3 quarters, down from 26% at year-end 2003.

We expect gearing to move back above 25% in 4Q, as a consequence of the normal year-end phasing of capital spending and German motor fuel excise tax payments.

Our policy remains as we stated in March.

As long as oil prices remain above $20 a barrel, we intend to distribute to shareholders 100% of all free cash flows in excess of investment and dividend needs.

The $10b we've distributed so far this year is consistent with this policy.

Our buybacks in the first 9 months totaled $5.5b and we've already purchased another $500m of shares in 4Q under our closed-period buy-back program.

Our year-to-date dividend of 20.95 cents per share is up 9% versus last year.

Our current quarterly dividend of 7.1 cents per share benefits from the additional increase in 2Q related to the reduction of our equity base from share buybacks.

Tightening market fundamentals now suggest a medium-term price support level of $30 per barrel, with the possibility of continued spikes to higher levels.

Since we remain cash balanced at around $20 per barrel, we should continue to see substantial free cash flow, which we intend to distribute to shareholders consistent with our financial framework and track record.

That concludes my prepared remarks.

We'd now be pleased to take your questions over the phone or the Internet.

[OPERATOR INSTRUCTIONS].

Right.

Well we'd like to take our first question, which I think comes from Neil Perry of Morgan Stanley.

Neil Perry.

Thanks Fergus.

Hi Byron.

Two questions.

First of all given that you've increased the CapEx numbers for future years, can you update us on where you see your cash breakeven for the Company now and the implications that has for what you said about buy-backs earlier this year.

I think you talked about total distribution over 3 years of about $35b under a $30 oil environment, and I wondered if that was still the case given the increase in CapEx.

And secondly on strategy, the comments John Brown is making about oil prices and refining margins are very substantially different from what you were saying 18 months ago, understandably.

But don't you think a structurally different view of market parameters calls for a different view in terms of your investment?

For example, you've always shunned heavy oil.

Perhaps it's time to review that policy?

Neil, with respect to your first question, which actually had 2 parts, we still are of the belief that the Company is at a cash balance point at $20 a barrel.

That's what our long term plans are based on and nothing, with respect to CapEx in a very different environment, the inflationary pressures that we're seeing, leads us to believe that if we're in a $20 environment, that we would not be cash balanced at $20.

The charts that you're referring to with respect to shareholder distributions that we presented in March, we -- we tracked that very carefully, and we would still be on track for that distribution and those sorts of oil price environments.

And if you extrapolate beyond that, we'd be on track for any extension of that chart, as well.

As far as the philosophy of the Company, we have to take a long term perpective on oil prices.

John has indicated that over the medium term that we think oil prices are underpinned at $30 a barrel.

But we have a wealth of projects in train and our Exploration and Production sector, building around the 5 new profit centers growing in Russia, and continuing to access additional opportunities on our existing centers.

We believe that the amount of capital that we're directing towards Exploration and Production and the types of investments that we are making are appropriate in today's environment, as indeed they were in the environment of 2003.

Thank you.

So, can I just confirm, what your saying is that --

Neil, did you have a follow up on that?

Well, it's just -- just to confirm that what your saying is really you still expect in the longer term oil prices and costs to decline back down to a more normal environment?

And what John Brown was talking about here is a transitory phase of $30 in the medium term?

I don't know what the longer term will bring any more than you do, Neil, and so we're talking a bit about hypothetical environments here.

If the environment comes back to $20 a barrel that would be consistent with a lot of the inflationary pressures which we're currently seeing in the marketplace abating at least over the course of time.

So we comfortable that the picture we painted for you in March remains intact. $20 a barrel is a financial framework that the Group has utilized for some time.

We think it remains the correct one and does not really necessarily reflect long-term positions with respect to oil prices, because they will be what they will be.

This is, at the current time, the appropriate way in BP's mind to continue to make resource allocation decisions between the Exploration and Production sector and the customer facing businesses and the right way to structure the basic distribution between investment in general and dividends to our shareholders.

Thank you.

Thank you, Neil.

I will now go to the US, and we've got a question from Robert Kestler at Simmons & Co.

Good afternoon, I was wondering, in light of the decision to sell your interest in Orman Lange and looking at the increase in your CapEx budget for 2005, I was wondering what, if any amount for that development is included in your current guidance?

Well, our guidance is based upon a build-up of a number of projects.

What I would remind you is that -- that the higher spending that I described to you in 2005 is the reflection of inflationary pressures in the sector, which may or may not come through in 2005, but if they continue at the rate that we've seen them in 2004 would amount to that level, as well as the exchange rate differences relative to what we had anticipated in 2003.

We're not expecting to have any material capital spending on Ormen Lange in 2005, because we would expect to complete a transaction somewhere towards the end of the year or early in 2005.

So is it fair to say that that was something that was previously included in your guidance and has now been removed, or was it excluded all along?

Previously, we would have been looking at 2005 to encompass a range of different projects.

We would, if I go back to 12 months ago, we were evaluating a number of projects for 2005.

Orman Lange would have been viewed as potentially one of those.

But the reasons for us disposing of it, which are that it is not strategic to BP, is something that was in our minds even as we discussed this project in the early part of 2004.

Okay.

Thank you very much.

Okay, coming back to the UK, J J Trainer from Deutsche Bank.

J J, are you there?

Yes, afternoon, A couple of questions.

You've previously stated some targets to expand cash returns at, I think, $20 oil prices.

And that target was predicated on getting better margins on new fields within the existing production base.

Are you still on track to achieve those better margins, given the cost pressures that you're now seeing?

And do you think those targets are still trackable in this $30 to $50 oil price world, or do they need restating?

And then a completely different question, actually -- he sterling dividend growth has been pretty anemic.

I wonder, why don't you hedge some oil and pay a special dividend?

Okay JJ.

I think I'll take the first one, and then Byron will take the second.

On the cash returns target you remember we gave one of the indicators back in our March strategy presentation, was to improve those cash returns by 2 percentage points by the end of 2006, and as Byron's shown we believe we're on track to do that.

Of course, that was predicated on the oil price of $20 a barrel.

In practice, of course, cash returns are significantly higher than they would be at $20 a barrel, and although there is some inflationary pressure on capital spending and indeed a little bit on costs, too, the increase in revenue that we're experiencing outweighs those pressures by a factor that's pretty close to 10:1.

So, we're considerably better off in terms of the cash returns metric than we would have been under the planning case at $20 a barrel.

But the underlying shape does remain on that $20 assumption, as we showed back in March.

On the question of why don't we sell oil forward to improve the sterling dividend?

Well, JJ, we've had this discussion before.

BP is fundamentally a dollar-based business.

We find that the bulk of our revenues come in terms of dollars.

The bulk of our capital spending and capital employed is dollar-based.

We structure our debt in terms of dollars, and it's only appropriate that we then structure our dividend payments in terms of dollars, as well.

To take some kind of special approach to discriminate towards one set of shareholders would be totally off the pitch.

And we certainly believe that our shareholders have the ability to understand our position on this, which is that it's dollar-based.

If there are swings and roundabouts, the sterling-based shareholders benefited substantially in the early part of this decade.

If the dollar strengthens again, they'll benefit disproportionately going forward.

Okay, thanks very much.

Okay, and going back to the US, we've got a question from Fred Load at Bear Stearns.

Fred, are you there?

Yes, guys, I have 3 questions.

First were there any revisions to oil and gas proved reserves?

I know third quarter is when you take a look at that.

Secondly, what would the seasonal impacts be do you think on price realizations in volume at TNK-BP in the fourth quarter?

And lastly, can you break down for us return on capital employed -- that 36% for the Company -- can you break that down by business segment?

I'll cover the first 2, and I'll ask Fergus to handle the third one.

Could you repeat the first question?

I didn't quite understand what aspect of reserves that you were asking about, Fred.

Byron, usually in the third quarter you take a look at your oil and gas reserves and make adjustments to the physical estimate of proved reserves under SEC Accounting.

And I'm just wondering if there were any adjustments in this third quarter period.

We don't do that in the third quarter.

We start a process in the third quarter, which then leads to the determination of the reserves we report at the end of the year.

Those are under [Sort] in the UK and under SEC regulations in the US.

As far as the fourth quarter volumes in TNK-BP, what is more likely to be the impact of adverse weather conditions in Russia is the ability to get the oil out of Russia to actually export it, whether it's in the form of crude and products or to have it positioned domestically.

And there obviously are differing net backs associated with whether or not you can export it into an international markets, although the additional tariff that's been put in place -- the export tariff duty -- takes away considerable amount of that benefit effective August 1, 2004.

Yes, Byron I know that.

I'm just wondering if you have an estimate on the impact of both your realizations and your volumes for the fourth quarter because of that seasonal effect?

Well, it can be very different in different years.

There have been winters -- and the winter of 2002/2003 was a very harsh winter -- which considerably impacted the ability to export volumes and had considerable impact, especially on domestic prices within Russia.

The winter of 2003/2004 was a much milder one, where volumes were able to be exported without too many material constraints.

So the only thing I know is that so far -- and we're obviously only at the very, very start of the winter -- there has been continued strength in domestic prices.

And what it turns out to be, as we go further into November, December, January period, will be totally dependant on the meteorological folks.

And for employed, yes.

The return on capital employed number that we showed was just actually under 20% for the third quarter of 2004, which is actually quite a similar number to what it was third quarter two years ago.

The big difference is, of course, that as we have invested heavily in the new profit centers and in Russia, our capital employed has grown over that period by something over $11b, which is about 15%.

So we are sustaining returns on a significantly expanded capital base.

In terms of segmental returns, as you know we don't currently report our segmental reports on a post-tax basis.

But that is something, in terms of the segmental levels of returns, either on a profit or cash basis, that we will probably talk to you about with our full-year results as we normally do.

So you will have to be a little bit patient before you get an update in terms of the underlying trends and in terms of segmental returns.

Moving back to the UK, we have a question.

Jeremy Olden at Lehman Brothers.

Jeremy, are you there?

Yes.

Good afternoon guys.

If I may, the classic 2 questions.

Do you have any guidance at all on how much higher tax rates may have cost you in the quarter and whether you see any more specific ones you know about in the pipeline to come through, particularly upstream I'm thinking of?

And secondly, do you have any guidance you are yet able to offer us on 2005 production levels?

Well, the key element in 2004 has been the increased export duties in Russia, and that did, indeed, have an impact on the third quarter numbers.

More importantly, it has an impact on the fourth quarter, because I outlined for you the impact of the price being the same in the fourth quarter as the third quarter.

Just having an additional -- just having an additional month of the higher tax is about half of the 160m.

So in today's environment, there is a substantial impact from the higher rates that have been applied to export volumes in Russia.

The effective tax rate on the margin is now approaching 90%.

So that probably more than anything else has been a determinant of the tax rate that we're seeing in 2004.

Obviously, on the margin, because we're taxed at 40% as opposed to the average tax rate of 35% that, kind of, across all of our businesses, we see, as prices go up, that the effective tax rate goes up a bit.

But we have managed to, in 2004, to offset that through a number of tax management measures.

As far as guidance for 2005, Jeremy, on the volume front, I'll just go back to what we told you in March, that we expect to have production growth from 2003 to 2008 between –- it would be 5%, on average, without TNK-BP, and 7% if you include TNK-BP.

Everything we see in 2004 and as we look into 2005 would indicate that that's on track, that we continue to have production from existing profit centers in line with the decline that was indicated.

And the major projects that will increase production from the new project centers are all on track.

In fact, in TNK-BP, if I add the third leg to the stool, volumes have grown faster than we anticipated.

But we are very comfortable with the indications we gave you and will be more specific, obviously, when we talk with you early in the New Year.

Right.

Thanks.

Jeremy, just building on that, you will recall that Byron indicated in July that the new export duty rates in Russia would impact TNK-BP earnings in the third quarter by about $65m.

That's about right and, as Byron says, above $25 a barrel Urals, we are looking at a marginal rate now of about 85%, taking the new duties and the production taxes together.

We've also seen some tax increases in Venezuela prospectively and Argentina.

But not material really in the context of the Group overall.

Going back to the U.S., Neil McMahon, Bernstein.

Neil, are you there?

Yes, indeed.

Thanks Fergus.

First of all, when you look at what you need to get through to the 4m barrels a day for the year, it looks like you need a cold autumn and start of the winter to get there for an uptake in your seasonal volumes.

Could you give us an update on the targets you set out for operational downtime, especially in the North Sea?

And basically to see how you're getting on with that for the fourth quarter and if you've got any planned levels of maintenance in the fourth quarter.

Then secondly, just on refining and marketing, could you give us a handle on how much of the refining result was driven by trading activities, versus actual refining optimization?

With respect to the second, no, we won't.

Our trading activity is totally integrated with respect to our underlying operations.

We would not have any trading activity if we didn't have refineries and gas-related assets in our portfolio.

So we don't tend to segment them out, even internally.

As far as the production for the fourth quarter and how that would relate to -- and I take issue with the word “target”.

We only have 3 targets and nothing with respect to production is a target.

It's an indicator, as, indeed, are the supporting metrics.

But the key drivers to production in the fourth quarter will relate to the speed at which we can get the Deepwater Gulf of Mexico operations back online.

The facilities themselves have been ready to go, as I indicated.

The challenge is getting the pipelines operable.

As we're sitting here discussing things today, we would see an impact in the fourth quarter of about 50,000 barrels a day from hurricane Ivan effects, and that's contingent upon getting the remaining approximately 145,000 barrels a day of shut-in production back online over the course of the next week or so.

Everything is going well, and we would expect that to occur.

But if there is further delay on getting these important producing assets online, then that will obviously impact the amount of production in 4Q.

Fergus?

Yes, I think your other part of your question was about we had an indicator of operating efficiency, which was part of our plan to mitigate the decline rate in our existing production centers.

I am pleased to tell you that despite some adverse events, such as the problems we've had in Egypt and, indeed, hurricane Ivan, it does look as if we are on track now for improvement in operating efficiency, from just under 90% to about 91% for the portfolio as a whole in 2004.

And, as we planned for, the most significant improvement is taking place in the North Sea, where operating efficiency looks like it's going to be about 4% higher than it was in a bitterly disappointing 2003.

So those things, I am pleased to say, are coming through.

And it's one of the reasons why were are confident in terms of the volume guidance that Byron has given you, despite hurricane Ivan and the high oil price, which has also, obviously, tended to depress our production volumes, as reported.

So you would say that in the North Sea you must be up to, what, the high 80% range now or something like that?

85 to 86%, Neil, yes.

You're right.

Right.

Thanks Fergus.

Coming back to the UK, we have a question from Mark [Yanotti] at Merrill Lynch.

Mark, are you there?

Yes, afternoon. 2 questions if I may.

The first question, this is the second consecutive quarter now we've seen an increase in CapEx.

Can you maybe just give us a feel for what has changed since the last quarter where you increased by 500 to 1b?

Can you maybe give us some examples of specific projects that you see overrunning or pushing higher on costs?

And should we be getting worried about your management information systems?

Second question is going back to CapEx.

Despite the price we have got today, CapEx -- sorry, back to the tax.

Tax rate's still 34.6% in the quarter.

Can you explain just how that CapEx remains so low and maybe give us some guidance for the Group tax rate for the full year and into next year?

I hear what you say about the second consecutive quarter.

We have increased capital guidance, but we have certainly not increased it very much for 2004.

And to the extent that we have increased it for 2004, it's a reflection of the sector-specific price and sector-specific cost inflation we see coming through.

There -- as indeed is the increase that we are indicating to you for 2005, there is not any material change in the activities.

The only thing that we're really changing for 2005 is to build into it some additional appraisal work that is a consequence of being even more successful on the exploration front than we had anticipated previously.

And we had anticipated a success, but we're finding even greater success.

So that's a good thing not a bad thing.

And we are not immune from the environment around us.

To the extent that foreign exchange rates go in one direction or another as the dollar strengthens or weakens, this will impact the capital spending.

The bulk of our capital spending is in terms of dollars, but about 20-25% of it tends to be in other currencies.

And that is a direct consequence of those currencies moving vis-a-vis the dollar.

And again, I have to relate back to how we started in 2003, which was against a much stronger oil environment or stronger dollar environment.

The trends that we're seeing now, we only picked up in the spring.

We have had a chance now to understand them much better, and we believe that all the stuff that -- a lot of people have been talking about steel prices, which impact industry in general, and within our sector we've seen steel prices going up 50 to 100%.

We're seeing rig rates going up at double-digit rates.

We're seeing a lot of services activity going up at double-digit rates.

We're seeing consumables going up well above 5%.

So we're seeing lots and lots of indications of pressures on the industry in general.

We are used to managing that cost increase.

When in the past we have seen underlying inflation about 2% or so a year, we have always found ways to more efficiently manage against it, and through normal practices, those efficiencies basically tend to offset any uplift.

But the scale we're seeing coming through now can't be mitigated in that fashion, and we're the beneficiary of having some very good supply chain management contracts in place, in particular on the tubular front.

But this will abate as we move into 2005, as I indicated.

So it's a reflection of the environment.

It's not a reflection materially of any increase in activity.

With reflection to your second question about the degree of tax rate, when I talked with all of you back in March and, as I have underscored almost on a quarterly basis since then, on the margin our tax rates -- our income tax rates will go up as we are taxed 40% on our incremental income contribution.

But we do a lot of things to try to ensure that it doesn't go up to the full effect of that.

And the fact that we have held it at 35% this year is a strong statement to the effectiveness of our tax on [inaudible].

And I will give further guidance in the spring, with respect to 2005.

But at the current time I see no reason to expect the rates will deviate from where you're seeing them today.

Okay.

Thanks.

Thank you, Mark.

Is there any follow-up question?

If not, then we'll move on to Gordon Grey from JP Morgan.

Gordon, are you there?

Yes I am.

It's just a quick question about refining.

You've -- apart from a bit of cost inflation, you haven't really changed your guidance on refining investment since early 2003.

I'm just wondering, in the light of what we see in terms of the tightness in the system and your comments on light-heavy spreads, whether you see a scope to make a higher level of strategic long-term investment in refining?

I think that's a fairly easy one, which if I may take, which is that today, as you know, refining, for a long period of time, has been pretty much a cost of capital if you were lucky business.

It's done a little bit better recently and that may be sustained for some uncertain period of time into the future.

But in terms of the scale of investment that would be required to materially change that exposure, I think it's far too soon to make any judgment on that.

And there's plenty more that can be done at the margin with the existing system before we would be looking at any material change in that area.

And if I could just add, Fergus, we continue to invest in the refineries and greenfields capability, and if the spreads we're seeing today were to persist then that would add incentive, as you're suggesting Gordon, to more material investments in upgrading capability in our existing refineries.

There are, as we pointed out earlier, very high across the portfolio as a whole, with respect to their underlying upgrading capability right now.

But it's something that John Manzoni and his team are pensing upon, that as far as the distribution of capital spending between the customer-facing segments and the upstream, we're continuing to follow the track that we have been on for a number of years, and that does, indeed, force choices.

It forces choices throughout our portfolio and that's a good thing not a bad thing.

Great.

Thanks.

We're now moving to Europe.

We have a question from [Pasqual Mingues] at Exane (ph).

Pasquale, are you there?

Yes, good afternoon.

Just a question, just following the presentation of Lord Brown saying that oil prices may have a support of around $30 per barrel for the medium term.

In that environment, what could be your capital expenditure being in 2005, for 2006 and 2007, based on the guidance given us earlier, in March 2004, and based on your ability, perhaps, to reconvert part of the inflationary pressure, if it is realistic or not?

We are not changing anything with respect to our view of oil prices over the medium term, medium term being 4 or 5 years, as John defined it.

We have an activity set.

We are running the business looking at a longer term capability.

And the appropriate distribution of the cash sources for the firm, amongst various types of capital spending and then distribution to our shareholders.

That framework that I've described remains intact.

And to the extent that there are higher oil prices -- and maybe much higher oil prices -- and that brings with it a slightly higher inflationary trend in the industry.

It in no way takes away from the underlying activity set around which we plan to invest.

Okay, it's worth being absolutely clear that the guidance we are giving for 2005 capital spending is based on the assumption that the environment that we have experienced in the third quarter persists through 2005.

So in that sense, it already reflects an environment where we have the inflationary pressures from the prices actually above the level that you were talking about.

I think it's very difficult to look too far out into the future on inflationary trends.

We're seeing what we're seeing right now.

It's different from what we've seen in the past.

We're trying to shape a picture for 2005 at the current time.

We're not trying to shape a picture beyond that because circumstances, as we look out over time, are going to be driven by the reality of the environment in which we're in.

So I'll leave it to you to decide how you might want to extrapolate the current environmental positions we're in.

Thanks.

Now coming back to the UK, Colin Smith from CSFB.

Colin, are you there?

Colin Smith, CSFB?

Right, we seem to have lost Colin.

Going back to the US Mark Gilman from Benchmark.

Mark, are you there?

Yes I am.

Can you hear me?

Can you hear me alright?

We can hear you fine.

Okay.

I just 3 unrelated questions, if I could.

First I was just wondering to what extent the decision to divest Orna Longd implies more extensive divestment of the Norwegian upstream asset base?

Secondly, the TNK dividend received, pursuant to what Byron said first half this year, fourth quarter last, would seem to imply a somewhat higher pay-out ratio than had been indicated previously.

I wonder if you could reiterate what BP-TNK's pay-out ratio philosophy will be going forward?

Third and finally, on the Gulf of Mexico production situation, could you just indicate what the actual impact of the storm-related shut-downs was in the third quarter and split those fourth quarter numbers that were mentioned a moment ago between oil and gas?

We'll take your questions in order, and I'll deal with the first two.

And Fergus will handle the third.

The decision to divest of Orna Longd, which is a non-operated and non-strategic asset.

It's a great asset.

No problems with that.

But we only had a 10% interest in it.

We were a non-operator.

And, as we looked around we felt that it's better positioning for BP to divest of this non-strategic asset and redeploy the funds elsewhere than to engage in the significant capital spending required to bring it online.

And we're confident that we will realize that full value of the project in the form of investment.

It in no way speaks to our interest in remaining a player in Norway.

It's still a small but important part of the BP portfolio.

There are some good oil-producing assets there.

And there's additional development opportunities in the future.

So no statement with respect to commitment to Norway.

As far as the TNK-BP dividend payment, you remember it was based upon pay-out relative to US GAAP, the minimum of 40% of the US GAAP income from TNK-BP -- and I underscore the word 'minimum'.

It didn't say what the maximum pay-out might be.

The company itself is attempting to manage its capital spending versus its distribution back to its owners in the context of a similar sort of gearing framework that BP has.

So, to some extent, it will be driven by that overall framework within TNK-BP.

And the dividends coming back from that, which you have seen so far this year, are a reflection thereof.

And finally, Mark, your question about the hurricane Ivan impact on the Gulf of Mexico production and its split between oil and gas.

The third quarter impact of hurricane Ivan was about 40,000 barrels of oil equivalent per day, of which around three quarters was oil and 25% gas.

Before you ask, the expectation is that the fourth quarter will be more like 50,000 barrels a day, with an approximately similar split between oil and gas.

So, as I say, that's work in progress as the fields are brought back on stream and the pipeline commission systems are re-commissioned.

Thanks very much, guys.

Coming back to the UK, Colin Smith.

Are you there this time?

I hope I am.

I hope you can hear me gentlemen, Byron and Fergus.

You've actually told us quite a lot today, or rather reminded us forcefully, that the strength of the macro background has more than outweighed the cost increases in the CapEx side.

How [indiscernible] that -- just a quick question on the assumption behind your point about gearing being back above 25% at the end of Q4, and can you just tell us what budget oil price you were using in Q4 when you make that calculation?

Well, I'm not going to speak to specific forecasts for the fourth quarter.

But I’d just remind you of the primary factors here.

One is that capital spending is disproportionate in the fourth quarter.

We have invested $10b over the first three quarters and we have indicated to you it will be just about $14b for the year as a whole.

So there will be more in 4Q.

And that's -- a lot of that tends to be driven in the refining and marketing business.

They tee up a lot of projects for the back side of the year.

Secondly, the swing, with respect to working capital associated with the German motor fuel vehicle excise tax, is about $2b out in the fourth quarter and then back in in the first quarter.

So you can see there's quite a big driver towards higher gearing in the fourth quarter.

The environment that exists in this quarter will be matched up by share buybacks to ensure that with all these conditions in place that we end up back within the gearing band that we have indicated.

So somewhere at about 25% at year end.

I think it's a measure of the same for cash flow, that no matter how hard we try to get gearing above 25%, we haven't managed it so far this year.

But, as Byron says, we should be there by the end of the fourth quarter.

Staying in the U.K., Andrew Archer from Commerzbank.

Andrew, are you there?

We seem to have lost Andrew.

So John Wright at Citibank?

Hi.

Thanks Fergus.

Just one question about TNK-BP.

I notice their debt has dropped below $700m, but is expected to rise up to $3b or higher by year end, a pretty sharp increase in capital expenditure.

I wondered if you could give an indication of what that was going towards?

Yes, I'd better take that one John because it was something that was covered by Kent Potter, the CFO of TNK-BP when we were out visiting the company back in September.

I think what Kent indicated at that point, John, was that the intention of TNK-BP was to primarily use the dividend as the mechanism to get the gearing back to their target range, which is also 25 to 35% debt to equity.

So I think it's really a question for Kent Potter, but I don't believe that's changed, in our understanding, since we heard that presentation in Moscow in September.

Okay, so there's no major acquisitions planned or minority buy-ups?

Not from what Kent indicated back in September, no.

Okay.

Thank you.

Staying in the UK, Paul Spedding (ph) from DKW.

Paul?

Good afternoon gentlemen.

Just a quick question on tax paid.

The third quarter tax payment looks relatively heavy by seasonal standards.

Could you, perhaps, talk a little bit about that?

Do you mean cash tax paid, Paul --?

That's the one.

You mean the former do you?

Cash of [indiscernible].

Paul, there's nothing out of the ordinary.

There was -- in the US last year, because of the particular timing that was part of the tax bill at that stage, the 3Q and 4Q tax payments both flowed into 4Q, so we're seeing that now spread across 3Q and 4Q in 2004.

Otherwise, it's a reflection of the normal phasing of tax payments.

They are larger because the profitability of the firm is larger.

But nothing unusual.

Thanks very much.

The comparison of 2003 and 2004, and if that's the case, it's because of the U.S. tax phasing.

Thanks, Paul.

Now we have a question from Paul McGanz (ph) from CIS.

Paul?

Good afternoon.

It's a question on capital allocation.

If I use your planning assumption of long term $20 oil, then I must confess that I struggle to get close to the current share price, and I know that most of the sulfide (ph) analysts need to use between $25 and $30 long term in order to value BP at over 500 pence.

My question is are you using one oil price assumption for operational planning, but a different oil price assumption to justify paying up to 550 pence per share in a buyback?

And shouldn't all potential uses of capital be competing on consistent assumptions?

The $20 framework that BP uses is merely that.

It's a framework that we use as a foundation for taking decisions on allocation of cash.

As I said earlier today, between various parts of BP, and between reinvestment back into the business, and the distribution to our shareholders, it serves that purpose and primarily that purpose.

We, purely as a Company, respond to the reality of the day.

And we make financial forecasts on the basis of the near-term prices that we are expecting.

And, consistent with the framework, the other framework that we provided investors in March, we felt that it is appropriate to take cash that is beyond the underlying needs of the firm and distribute it back to shareholders in the form of share buybacks.

We're not attempting to make a projection as a Company of what is the appropriate valuation of our shares.

That's for you and other of our shareholders to decide.

Are you saying, then, that you're indifferent to buying back BP shares at, say, either 300 pence or 900 pence?

Thanks, Paul.

Interesting question.

And now Andrew Archer from Commerzank.

I think Andrew, hopefully we have you back?

Yes, sorry about that.

Just quick questions.

Firstly can you just clarify that on the CapEx increase that none of those arise from any cost overruns, in the traditional sense, against your current development projects.

And then secondly, just you specifically mentioned oil service pricing pressure.

Can you say where you're seeing that most within your business and ideally geographically, as well?

I'll let Fergus cover the first point.

I'll cover the second.

We're seeing it primarily where competition for resources and the fervor of the industry is at its peak.

And so, not surprisingly, we see this strongest in the Gulf of Mexico and onshore, the lower 48, because of the intense activity set there.

We see it less in some of the other mature provinces where there hasn't been quite the same incremental ramp-up in activity.

For example, in our case, in Alaska and, to a similar but perhaps lesser extent, in the North Sea.

So this is, I think, you should take it as it's focused most heavily in the lower 48 and the Gulf of Mexico and it radiates out from there in its intensity.

Yes, coming back, Andrew, to your question about cost overruns within the capital guidance.

It's worth noting that in the guidance that we gave you back in March, there was an allowance for some projects to go better and some projects to go worse.

And in that sense there was headroom for some minor cost overruns.

So that was included in the numbers we gave you in March.

And it's not part of the shift in the guidance that we're giving you, Byron gave in July and that we've built on today.

The drivers there, just to be absolutely clear, are first and foremost the sector-specific inflation that we see as a result of the warmed-up economic and sectoral environment.

Secondly, the foreign exchange pressure, the continued weak dollar.

And, as a last, but relatively minor element, an increased level of activity in terms of appraisal of exploration success.

So those 3 things are the drivers of the revised guidance, nothing to do with individual projects.

That's great.

Thanks very much.

And in the UK Ian Reed (ph).

Thank you for being so patient, Ian.

Ian Reed from UBS.

Hi there gentlemen. 2 questions please.

Firstly, Byron, you talked about the impact of light-heavy spread on your downstream business and how you are benefiting from that due to the sophistication of your refining business.

But I wonder whether you could also try and quantify what the impact is in the upstream because obviously you are producing somewhat of a heavy slate (ph) as well, or a heavier slate than Brent (ph), certainly.

So if we continue to see these sorts of differentials from Brent of heavy crudes going into the fourth quarter, what is the net benefit, or loss, if you like, for BP?

And secondly, on the Trinidad's LNG gas contract issue, which came up a couple of weeks ago.

I wonder if you can just comment on what your understanding of that issue is going forward and what the impact might be for BP?

Could you repeat the second question, Ian?

I didn't hear the first part.

Yes, that LNG potential renegotiation of gas contracts -- or reopening of gas contracts, as I think they called it.

I'll take the first one, and Fergus will respond to the second.

If you look across our portfolio, the -- go to the new profit centers in particular, the bulk of the production from there is lighter as opposed to heavier.

The Deepwater Gulf is light and Angola is certainly light.

The crude coming out at the Caskan (ph) is light-ish.

So the new profit centers that are oil oriented, as opposed to Trinidad and Asia-Pacific gas, tend to bring with it increased light-oil production.

Obviously in Russia it tends to be a bit on the heavier side.

But if we look across our production portfolio, I would have characterized it as more light in nature than heavy in nature.

And we certainly have found realizations from our production not to be particularly lagging the average crude realization out there over this sharp run-up period in oil prices.

Yes, Ian, you can quantify that obviously with the realization data relative to the markers that we give you in the stock exchange announcement.

Coming to your second question, I suspect you are referring to Trinidad, where the energy minister made a statement to Parliament just recently, talking about contracts under Atlantic LNG Chains 123.

The government has raised some concerns and we're working with them to address those concerns, as we do with the governments in all the areas in which we operate.

So really that's just part of business as usual as far as we're concerned, and we'll let you know when there's an outcome to those discussions.

Can I just get a follow-up on the first question?

Please go ahead.

Yes, just to give some guidance on if another dollar, if you like, drops off the heavy-light differential, is that a beneficial event for BP, or do you lose as much in the upstream as you gain in the downstream?

Well, we're clearly more geared in that sort of situation in the upstream than we are in the downstream.

Okay.

Thanks for that.

Thanks Ian. [Nicholas Sowell] from CSFB.

Nicholas, are you there?

Hello?

Yes.

No, sorry, I don't have any further questions.

Thank you very much.

And finally, I think Pasqual Mingues from Exane has got a follow-up question.

Pasqual?

Yes, thank you very much.

I have a follow-up question regarding your gearing expectation to go back above 25% by the year end.

I was wondering if it takes into account the fact that Solvay could exercise its [puts]?

And, if you have taken this assumption, could you also recall the amount of these [puts]?

The Solvay [put] agreement, as you note, comes into -- becomes operational in the month of November.

The gearing that I described does not factor -- this is not a factor in the gearing statement that I made earlier.

That's fine.

Thank you very much, Pasqual.

Unless anybody has got any other questions, I think we have reached the end of the conference call.

I'd just like to thank everybody for their interest and we look forward to speaking to you next quarter.

As ever, if you have any other follow-up questions, please feel free to contact the Investor Relations Department.

Thanks very much everybody.