英國石油 (BP) 2003 Q3 法說會逐字稿

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

I would now like to turn the call over to Fergus McLeod, Head of Investor relations.

Please answer.

Good afternoon for those of you listening in Europe and Asia, and good morning to those in the Americas.

It is my pleasure to welcome you to BP's third-quarter 2003 conference call.

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

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

Before we start, I would just like to draw your attention to a couple of items.

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

If you're listing on the telephone, the slides are available to download from the investor center on our website -- BP.com.

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

If you haven't got them and would like to be placed on our list, please do let us know.

Secondly, I would like to draw your attention to the words on 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 forecast for a number of reason, such as those noted on this slide.

I would now like to hand over to Byron Grote, BP's Chief Financial Officer.

Thank you, Fergus.

I will begin with an overview of our business results for the third quarter and year-to-date.

Following that, I will highlight the continuing strategic progress each business segment is making against the plans we reviewed earlier in the year, then Fergus and I will be happy to take your questions.

Trading (ph) conditions in the third quarter remained relatively strong in all areas but petrochemical.

I will focus on the quarterly figures on the left of this slide.

Our average liquids realization, which includes both oil and NGLs, was nearly $27 per barrel, up around $2 compared with the third quarter of last year, as well as the second quarter.

Our average natural gas realization of $3.08 per thousand cubic feet remained well above prior year levels, but was down 9 percent on the second quarter.

In North America, we were the largest producer.

Gas continued trading at a premium to residual fuel oil as the industry built for inventories for the winter.

Regional differentials narrowed following the opening of the Kern River pipeline expansion between the Rockies and California.

Taking oil and gas prices together, our average realized hydrocarbon price was 1 percent higher than in the second quarter and up 17 percent over the third quarter of last year.

Our refining indicator margin of $4.59 per barrel was also higher than either comparison period, although our actual margins did not show quite the same increase.

Refining margins peaked in August and softened as the quarter closed.

Although not shown, retail fuel margins continued to be strong relative to 2002 but were around 20 percent below second quarter levels.

Overall, the downstream trading environment was comparable to the first quarter.

Petrochemicals margins, particularly in Europe, were squeezed by the rise in feedstock prices.

Our petrochemicals indicator margin fell by $25 per ton compared with the second quarter.

Overall, as shown on the right of the slide, so far in 2003, prices and indicator margins have been higher than in 2002 across all of our business segments.

Helped by these price and margin conditions, our financial results remain strong compared with those of a year ago.

This slide shows key results for the third quarter and year-to-date.

I will focus on this quarter's results shown on the top of the slide.

Our pro forma result of $2.9 billion was 25 percent higher than in the third quarter of last year.

Our replacement cost profit, which includes special items and acquisition impacts, was $2.1 billion, nearly triple that over the prior year.

Our historic cost profit, which also includes disposable and inventory impacts, was $2.4 billion, down 16 percent.

This historic result is of course dominated by unrealized inventory gains and losses caused by volatility in hydrocarbon prices.

Of all of these measures, we continue to believe that the pro forma result is the most valid and consistent indicator of our underlying profitability and the measure most comparable to others in our industry.

Our improved results continued to flowthrough to operating cash flow, which at $4.9 billion in Q3, was up 12 percent on last year.

This includes nearly $650 million of pension funding during the third quarter.

Before the pension funding, the increase was 27 percent.

A 6.5 cent dividend was announced today, representing an 8 percent increase compared with the third quarter of last year.

The dollar weakened by 9 percent over the last year, so the equivalent sterling dividend is 1 percent lower than in the third quarter of 2002.

Since the start of 1999 when we moved to a dollar based dividend, we have increased the dollar dividend by 30 percent.

Sterling dividend has risen by 26 percent, despite the weak dollar.

This represents a compound growth rate since 1999 of 8 percent per year in dollars terms and 7 percent per year in sterling, both of which comfortably exceed inflation over this time period, in line with our long-term track record.

These are strong results.

The year-to-date comparison summarized on the lower part of this slide is comparable, and in some cases even stronger as it incorporates our record results for the first quarter of 2003.

This is the first quarter our results will include our 50 percent interest in TNK BP.

Our stock exchange announcement contains a supplemental data joined the contribution TNK BP made to our third quarter results since the transaction completed on the 29th of August.

This slide highlights two key metrics -- earnings and production volume for our 33 days of ownership in Q3.

Before focusing on the data, let me summarize our reporting process for TNK BP.

TNK BP prepares its accounts in U.S.

GAAP and takes longer to close its books than the time available, before we announce BP's quarterly results.

The figures BP reports are therefore based on preliminary U.S.

GAAP data provided by TNK BP which we independently validate.

Then as I explained in our presentation earlier this month, we make adjustments to reflect BP's ownership -- our acquisition cost, SEC reserve estimates and the like and translate it into UK GAAP.

We receive final figures from TNK BP later in the quarter and will reflect any differences between our estimate and the actuals and results for the subsequent quarter.

This will be a reoccurring feature for the TNK BP closing process until it can be accelerated to match BP's external reporting cycle.

Returning to the figures on the slide, our third quarter results include a $105 million contribution from TNK BP covering the 33 days since the 29th of August.

This consists of our $114 million share of TNK BP's net income, less than $9 million unwinding on the discount on the deferred share payment.

When compared with the first half results we discussed earlier this month, it is clear that TNK BP profitability improved substantially in the third quarter.

Several factors drove this improvement.

TNK BP's total production, including both crude oil and natural gas to be consistent with BP's reporting conventions, was up 5 percent in the third quarter compared to the first half of 2003 and by around 16 percent compared to Q3 of last year.

For the 33 days of ownership, our share of TNK BP volumes was 695 barrels of oil equivalent per day, or 249,000 if spread over the quarter as a whole.

Secondly, TNK BP exported 78 percent of its Q3 crude and product production international markets, achieving high realizations overall than that available in the Russian domestic crude market.

This is up from 69 percent in the first half.

Thirdly, Russian domestic prices in the third quarter were more than twice as high as in the first half which was depressed due to local supply and demand conditions.

We expect domestic Russian prices to moderate somewhat in the fourth quarter. (indiscernible) these results are encouraging, but it is still early days.

We remain excited about the potential that TNK BP adds to our diverse portfolio.

Turning now to return on capital employed, this slide shows BP's pro forma return history relative to our principal competitors.

All results are calculated using a consistent approach which we believe reflects industry best practice.

Our returns remain competitive with those of our peers within a band driven by the industry price and margin cycle that is evident from the chart.

Our 15 percent return in the third quarter fully reflects a number of items, including a small adverse impact around a half-point related to the weakening of the dollar over the past year; the significant capital we're investing in our distinctive portfolio of new upstream profit centers which depressive near-term returns but which we expect to contribute increasingly to the bottom line over the next several years; a favorable impact of disposing lower return assets that are not core to our strategies and inclusion of TNK BP from the 29th of August, which as expected, has been accretive to our return on capital employed.

This slide shows the main factors driving the $3.6 billion improvement in our year-to-date pro forma results from around $6 billion in 2002 to nearly $10 billion in 2003.

Higher prices and margins are clearly the dominant factor with a post tax benefit of $4.3 billion.

Compared with last year, our year-to-date results benefited by $1.2 billion from higher oil prices, $1.8 billion from higher gas prices and $1.3 billion from higher refining and marketing margins.

As in the second quarter, we have shown foreign exchange impacts separately.

Appreciation of other currencies against the dollar increased both our revenues and cost by roughly offsetting amounts.

The net impact of 4X (ph) movements was small, around $100 million which indicates the natural hedge inherent across our businesses.

Portfolio activities reduced our post-tax results by around $300 million compared to last year.

This includes year-to-date impacts of about $250 million from E&P disposals, $100 million from the sale of our Ruhrgas interest in the middle of last year and smaller amounts in refining and marketing and petrochemicals.

These were partially offset by the incremental earnings contribution from TNK BP.

Higher depreciation, depletion and amortization charges this year reduced our nine months results by around $600 million compared with 2002.

Of course, these higher DD&A charges will have no impact on our cash generation.

The remaining item of around $300 million has a number of components.

It includes around $200 million for increased tension and postretirement benefit cost, consistent with the full-year expectation I previously mentioned.

It also includes a small year-on-year increase in charges for future environmental remediation liabilities.

I will come back to the environmental remediation charges in a few moments.

Offsetting these items, we saw continued benefits from lower interest expense and a lower effective tax rate, which benefited our year-to-date results by $200 million and $100 million, respectively.

Other factors netted to an improvement of around $200 million dollars year-on-year.

These include volume and underlying cost improvements across all our operations which more than offset cost inflation.

The pro forma results just discussed are before special and exceptional items.

This chart highlights our track record of special and exceptional items since the start of last year.

So far this year, our cumulative disposal gains of around $850 million have more than offset the $320 million of net special charges for restructuring and impairments and a third quarter charge of around $240 million in respect to a reassessment of our existing environmental remediation provisions.

This results in a positive year-on-year pretax special and exceptional balance of nearly $300 million which we have excluded from our pro forma result.

The insert table provides a further breakout of our third quarter exceptional and special items.

It also highlights additional one-off charges included in our pro forma results as noted in our SEA (ph).

As mentioned earlier, these include some charges in respect of environmental remediation costs.

Let me briefly explain these charges further.

We review the status of our environmental provisions annually and have now consolidated this review in the third quarter.

This can give rise to ordinary charges against earnings.

In the third quarter, the review indicated the requirement for a $255 million charge which we have taken above the line.

This is likely to be a recurring feature of our results in the third quarter of each year.

On this occasion, the review also supported a special charge of around $240 million due to a change in methodology used to determine the liabilities, mainly in refining and marketing.

Our long-standing financial framework includes balancing sources and uses of cash over the business cycle.

Our 25-35 percent gearing band (ph) gives us flexibility to sustain our underlying business strategies and to time our acquisitions and disposals based on opportunities and market conditions.

This chart shows our sources and uses of cash for the first nine months of 2002 and of 2003.

Each pair of bars represents a single year with cash sources on the left and uses on the right.

The improvement in trading conditions between last year and this year is evident in the cash from operations shown here in green, which grew from $13.1 billion in 2002 to $18.2 billion in 2003.

These figures are after pension fund contribution.

As you recall, we are using some of this year’s cash flow to address the deficits in our funded pension plan.

Our pension contributions to date in 2003 total $950 million pretax, including nearly 650 million in the third quarter as I mentioned previously.

During the fourth quarter, we expect to complete the $2 billion second half discretionary funding program which I described in July.

Our organic capital spend, shown in pale blue, so far in 2003 has been around $9.5 billion, up slightly from last year.

We have been continuously hydrating (ph) our expenditures and the year and now expect full-year capital expenditures to be slightly below the range of 14-14.5 billion which I have indicated previously.

Portfolio activity in the first nine months of 2003 includes disposables totaling $5 billion, partially offset by $2.8 billion of acquisition, notably the first payment for TNK BP.

Most of this portfolio upgrading was in the upstream where we were able to capitalize on strong buyer interest during a period of high prices.

We expect our full-year disposals to be around $6 billion at the upper end of the range indicated in February.

Our full-year acquisitions are likely to exceed $4 billion upon our payment with respect to TNK BP's acquisitions of a 50 percent interest in Slavneft, which we expect to close in the fourth quarter.

Our year-to-date dividend is $4.2 billion.

We also bought back $2 billion of BP shares in the first half.

Share buybacks remain a priority during periods like this of strong free cash flow consistent with our financial framework.

However, given our other priorities, including the purchase of the Slavneft interest, which now looks likely to close earlier than forecast back in July and the pension prefunding I've already mentioned, we do not now currently plan any buybacks during the fourth quarter.

Our net debt ratio increased from 22 percent at midyear to 23 percent at the end of the third quarter, remaining below our 25-35 percent target range.

The third quarter increase included the impact of the TNK BP acquisition payment and $650 million of discretionary pension funding.

We expect to return to our target range in the fourth quarter.

That completes my review of the group financial results.

I would now like to summarize the progress each of our business segments is making in implementing the plans and strategies we described in February.

In February, we indicated that we expected our underlying upstream production capacity to grow by between zero and 3 percent in 2003, excluding the impact of acquisitions and divestments.

We remain on-track to achieve this.

Our reported production increased to more than 3.5 million barrels of oil equivalent per day in the third quarter, representing over 1.7 percent growth relative to the third quarter of 2002.

Within this production, we have significant impacts from both the TNK BP acquisition and our disposal program.

TNK BP added a gross 249,000 barrels of oil equivalent per day to our third quarter production.

Deducting the volume from the Sedanko (ph) interest, which we are ready owned, gives (ph) a net increase of 208,000 barrels of oil equivalent per day.

This more than offset the year-to-date disposal impact totaling 179,000 barrels a day in Q3 compared with last year.

Excluding these portfolio changes, our organic production rose.

This was despite our third quarter numbers being reduced by an estimated 25,000 barrels a day due to the impact of high oil prices on production sharing contract volumes and high gas prices has led us to choose to restrict NGL production in order to capture more value in the gas stream.

B&P segment continues on track with the strategy reviewed in February.

During the quarter, we made significant progress towards completion of our billed projects with the bulk of our capital spending is being directed.

The Kapok field in Trinidad started in July, supplying gas to train three (ph).

In preparation for startup, the Na Kika tension leg platform has arrived on location in the deepwater Gulf of Mexico and the Shakumba (ph) FPSO is on location in the Angola.

In Azerbaijan, construction is well advanced on our Azeri project, with sail-away of the drilling support module and the loading of living quarters on the central platform.

Construction began on the Shack Denise (ph) platform ahead of schedule.

In addition, significant headway is being made on the BTC pipeline, which is on track for startup in early 2005.

Turning to our produced business, all of our major indicators are on track.

After adjusting for disposals and some operational efficiency issues, our underlying base still declined is as expected at around 3 percent.

After correcting for environmental conditions, we remain on track for our lifting cost targets.

We are confident that our overall level of capital spending will come in below the bottom end of the range of $9.8-$10.2 billion discussed in February due to portfolio actions being taken and optimization of our investment options.

So far this year, we have received $4 billion of upstream disposal proceeds with the completion of a series of transactions in China, Algeria, the lower 48 and Venezuela in Q3.

Our disposal program has been accretive to our return on capital employed.

In refining and marketing, our performance year-to-date has been driven by our continued focus on capturing and expanding margin while driving for greater cost efficiency.

Our performance in refining was underpinned by another quarter with refining availability of 96 percent, about the level which we have averaged over the last eight quarters.

Overall volumes declined in our customer facing businesses, reflecting our asset high-grading program.

However, this high-grading continues to drive higher profitability and good volume growth on a like-for-like basis.

Retail saw same site volume growth of 1.7 percent and same-store sales growth of 3 percent.

Lubricants volumes grew by 1.5 percent.

We've increased the number of markets where we have introduced our new premium retail fuel, (indiscernible) in the gasoline and diesel this quarter.

Early results are very encouraging.

Gas costs are falling with Q3 showing a 1 percent reduction in unit costs on a like-for-like basis.

We're making good progress towards our main objectives in our other businesses.

Just a few highlights here today.

We continue to maximize value through an enhanced focus on gas marketing.

During the past quarter, we have made our first LNG deliveries to the Bilboa and Copone (ph) facilities as we build markets ahead of supply.

In solar, we review our operations and are rationalizing our manufacturing capability and reducing staff levels to improve the long-term profitability of the business.

In petrochemicals, we're focusing our efforts on growing our core product capacity and improving the quality and alignment of our portfolio.

For example, we have grown capacity in PTA in Asia were we started up two new plants and deepened our share of two existing joint ventures.

We have also added capacity in high-density polyethylene.

We're maintaining our push for functional excellence and growth in gross margins.

Cash fixed (ph) cost per ton are down 3 present percent since the start of the year, on track for our goal of a 40 percent reduction between 1998 and 2003.

To summarize -- our financials remain robust.

We have strengthened our pension funds and our balance sheet while returning more than $6 billion of cash to shareholders so far this year.

We have upgraded our portfolio in all segments.

Our six E&P growth areas, which now include TNK BP, are performing well.

Our downstream businesses continued to progress their strategies and capture available gross margin, despite difficult trading conditions for some parts of the business.

All in all, a strong quarter and nine months.

That concludes my prepared remarks.

We will now be pleased to take your questions over the phone or the Internet, and I will ask Fergus to moderate Q&A session.

(Operator Instructions).

Steve Pfiefer, Merrill Lynch & Co.

Thank you.

A real quick question.

I just wanted to make sure I understand the ordinary and special and exceptional items in the quarter.

I think you said that there would be some items that would be continuing in the third quarter, the 255 million of environmental.

Is that just a third quarter continuing item, or is that something that is a quarter-to-quarter event or annualized of about $1 billion?

In the past, we've tended to cluster a portion of it around the third quarter, in particular in refining and marketing.

But if you look back at charges in 2002, they were spread across each quarter and the year, although peaking in 3Q.

What we have done now is put in place a process where we're going to review these comprehensively across the group during the period leading up to our Q3 results.

And unless some unforeseen item occurs then in the fourth quarter, we would expect there to be only one reporting of these provisions on an annualized basis.

So what you are seeing in 2003, you can expect to occur in subsequent years.

As far as the scale of it, this is based upon a comprehensive review side by side, and so one can never predict the levels going forward.

I just referred to you the track record here, which was $180 million of ordinary charges in 2001 and 312 million in 2002.

So asked another way, from 3Q to 4Q, you would expect to see an absence of that $255 million environmental ordinary charges, if you will, and then it builds as you go through next year and say next third quarter, it would be roughly 255 million -- is that another way to think of it?

We would not contemplate any fourth-quarter charges at this time.

I said that there is always the possibility of something materializing, but we're putting this on an annual cycle now.

And as you said, you should anticipate the absence of these provisions in 4Q, 1Q and 2Q and a charge based upon an updating of the various environmental liabilities to occur in the third quarter 2004.

Great, thank you.

Neil Perry (ph), UBS.

Two questions, please.

One, you mentioned depreciation, but depreciation actually fell in the third quarter relative to the second quarter and the first quarter.

I wondered if you could comment on that, given that obviously volumes are higher.

And secondly, can I ask about chemicals, because the outlook statement from you and others remain very sanguine.

You talk about 3 percent reductions in cost, but is it not time to think about something a bit more radical with the chemicals division?

I think you still have something like 12 percent of your capital employed in chemicals.

Is there any review process going on as to how you are treating that part of the business?

We tried to get the numbers you are referencing on depreciation.

Let me address the chemicals strategy issue that you raised.

We remain committed to petrochemicals as part of the integrated oil business that we've put in place.

If you look at the capital spending that is going into this segment, we certainly have slowed it down over the course of the last several years.

Started doing that when I was the chief executive of the petrochemicals division and it has been continued by Ian Conn, my successor.

Certainly returns have not been at a level that is satisfactory at this point and time, but we would anticipate a return of margins to higher levels as demand and supply globally come more back in balance.

And looking forward, you should expect us to continue to focus on our core portfolio of seven products, which we laid out very clearly to investors in our strategy presentation in February and to the divesting of those other products where we do not believe we have a competitive advantage vis-a-vis competitors.

So the new money is going into the core products.

We are on a process of divesting the non-core areas and we believe that the result of that, as well as the slowdown in capital spending into the area, will improve results and we may find them improve quite substantially when demand/supply balances lead to better margins in the sector.

With your question about depreciation, I think the key thing is to remember there was an impairment in the third quarter of last year, which meant that the number that you see in the cash flow statement (indiscernible) 3.5 billion is somewhat misleading.

The underlying DD&A number, that thing excluding any impairment and actually (indiscernible) just excluding acquisition amortization, was running at about $1.7, $1.8 billion a quarter during 2002.

In 2003, it has been running about $2 billion, plus the acquisition amortization on top of that of around 500 million.

So I hope that gives you some sense of the underlying number.

I think what you're seeing this time round is that last year was rather distorted by impairments, and this year, there is a much cleaner number.

Does that answer your question, Neil?

Right. (indiscernible) We'll take a question from Fredrick Leuffer, at Bear Stearns.

Good afternoon, guys.

Two questions.

First, it looked like corporate and other expenses were higher, at least (indiscernible) I was looking for and higher than they have been recently, even adjusting for the environmental provisions.

Can you talk about what factors pushed cost up and maybe give us a little guidance going forward?

That's the first question.

You want to give us a second question as well, Fred?

Sure, Byron.

It looks like you have charges of $132 million in corporate and other, and 45 million in renewables.

They were mentioned, but they are not shown as special items to arrive at the adjusted earnings.

And maybe you can explain what the accounting rational is for that.

As far as corporate and other, you're right to suggest that you need to take the number and pull out from it the ordinary charge for remediation that is part of the 3Q result.

So you start with $320 million, you take the 132 out.

That gives 188.

I agree that this is more than we saw in the first quarter and the second quarter, which averaged about $150 million for 90 days.

There are also -- and we've not mentioned it -- but there are also a number of smaller once-off items which are increasing it by approximately another $20 million, which pulls it down into the range in which we saw in the first quarter.

If you are looking out in time, this is a very difficult area to pin down with fine accuracy, because we have just been describing a number of once-off effects that tend to cluster into the corporate area.

There also tend to be timing and phasing issues on cost as well.

The level in which we have experienced over the last three quarters, somewhere between $150 and $200 million, is probably good guidance for going forward, but it could on a quarterly basis fall outside of that range because of the once-off factors that I've set either above it or below it.

And clearly, we have seen above it this quarter, we saw below it last quarter.

But if driving through all of this we have seen no degradation in the underlying cost structure of the group as a whole.

So we've got a few things that are going to feature as we look out next year.

One of those is the fact that we have now sold the coal business.

So our pretax earnings, which were about $50 million a year last year, they have been running less than that this year, will no longer be a part of the other business in the corporate sector.

As far as the difference, I'm not quite sure where you are headed with your question, Fred, but let me answer it generically and then you can tell me whether or not I have adequately met your needs.

We're trying to distinguish on the special side, items that truly are both material and they are non-recurring.

And it is our view that, because the items on remediation management that were associated with using a new measurement technique had nothing really to do with addressing new liabilities, it was merely a method of measuring old liabilities, was most properly treated as a special item, and we have indeed done so.

Other remediation expenditures, which have to do with new estimations based upon new news of old liabilities, or the addition of new liabilities, whether they were in refining and marketing or whether they were in the corporate sector -- because this is an ongoing item, and I just referred to the fact that we will update these measurements every year in the third quarter -- are properly treated as an ordinary charge.

And when we looked at the restructuring in the solar business, the other charge that you referred to of $45 million, this was a component parts -- there are a lot of little things here which were basically addressing the fast changing technology that we are experiencing in the total (indiscernible) area.

And we felt that this was appropriate to treat as an ordinary charge as well, because periodically, we will find some technologies, some production no longer valuable for customers and it will need to be written down, and therefore, it's a feature of being in this business and properly treated as an ordinary charge.

But not on the renewables, but not ongoing?

I didn't -- we've treated the solar charge as an ordinary charge as a decrement to income.

It is a restructuring charge in the third quarter and we would not expect this charge to occur on an ongoing quarterly basis, if that's what you're asking.

That is what I'm asking, yes.

From time to time, there will probably be some charges in this area, but we will treat them as above the line.

Jeremy Elden, Lehman Brothers.

Good afternoon.

A couple of simple questions, I hope.

Could you let us know where in the cash flow statement we find the pension voluntary payments?

I suspect they might be split between lines.

And secondly on the Plutonio (ph) project in Angola, you did not mention -- there's been some talk that that is now going to be delayed at the request of the Angolan government.

Could you comment on that?

Let me take the first one, although I'm not sure I can refer you to the specific line.

I can assure you that what we have done is we have paid out $650 million into our various pension funds around the world, primarily to the U.S.

And I am advised that it goes up as debtors in the cash flow. (multiple speakers) as far as (indiscernible), can we come back to that one, Jeremy?

We will just take that out for you Jeremy and come back to back to you before the end of the call.

Thanks, guys.

Mark Gillman, First Albany.

Good afternoon.

I had two questions, one relating to be amalgamation of BP TNK.

I wonder if you could clarify, because I'm confused from the table in the stock exchange announcement -- where the additional BP DD&A flows into the accounts?

Also with respect to that, I had been of the assumption that the interest expense associated with all elements of BP TNK, including the joint ventures interest, was to be in your interest category.

The stock exchange announcement suggests that there is interest in a replacement cost number.

The second question referred to the refining and marketing area.

The results were well short of our expectations.

I'm curious as to whether there were significant trading shortfalls, particularly in the UK, or whether some attention is being paid to what appears now to be a consistent shortfall in your refining and marketing performance relative to indicators?

Let me answer the first question, Mark.

TNK BP's DD&A is not in BP's depreciation charge.

BP includes only the operating profit, tax (ph) and interest.

So DD&A is actually contained in the ARCOP (ph) line.

What about the amortization of the BP investment, Byron?

Where is that?

That will show up as a DD&A charge, but it is obviously a very small amount in the third quarter.

What happens is under UK growth equity accounting rules, the third point at which you see it in BP's accounts (indiscernible) replacing cost operating profit level.

And you're quite right -- the interest expense, our share of interest expense is all shown there in note 9 on page 24 of the stock exchange announcement.

(indiscernible) your share of the joint ventures interest?

We can speak for what your expectations were for the performance of the business.

It is the case that realized margins within the business fell somewhat short of what would have been indicated by our own externally published indicators, the so-called defining gross margins.

And that reflected a number of factors, specifically the precise configuration of our refining system relative to that that was used in the calculation of the gross margin.

So there was a way in which I suppose an externally published indicator for us didn't reflect truly and fully the actual trading conditions experienced by our actual portfolio.

Does that answer your question, or did you want to come back of any part of your question?

I specifically asked whether trading results were adverse in the quarter and might explain the negative figure in UK refining and marketing.

And I'm sorry -- I'm still not clear on where the BP TNK interest expense is flowing through the consolidated accounts.

Is that in RCOP, or is it in your BP interest expense line?

I understand where you're going now, Mark.

If you look at the notes on the SEA and note 6, interest expense, you will see the line item joint ventures -- that $23 million includes approximately $13 million from TNK BP, and then you see also in that column the $9 million associated with the unwinding.

Obviously, the interest charges of TNK BP show up through the RCOP line as Fergus referred to earlier.

We will be happy to take you through off-line exactly how this works.

We appreciate that not everybody may be fully familiar with a UK accounting treatment on joint ventures.

To answer your question on refining and marketing, the answer is there was no major swing in trading.

It was principally the point that I made earlier, whereby published public domain indicator margins, including the one we published ourselves in our trading update didn't fully reflect the actual experience of our specific system in the quarter.

(indiscernible) the next question, I'd just like to go back to Jeremy Elden.

Jeremy, there is no change really, in terms of our plans on Plutonio (ph).

The project is, as far as we're concerned, running to potential, in terms of what we said about that project previously.

The timing of it is pretty much as expected and as expressed in our major project supplement that we had with our presentation on February 11.

We sanctioned (ph) it in the first quarter, we're currently seeking some Angola (ph) improvement to initiate execution.

It will be our first operation project in Angola, single hub development, FDFO (ph), accessing reserves in six fields, (indiscernible).

And as far as we're concerned, on-stream in 2007, if there are no changes there.

Coming back to the UK, Rod MacLean (ph) from CSFB.

Two questions unrelated actually.

Just back on TNK BP, would it be possible to -- or for Byron to give us an idea of what the net revenues were?

I appreciate there's only for 33 days, but any view on what the net revenue number was?

And also, minority -- the minority charge seemed significantly lower than I would have expected, and also significantly lower than your first-half guidance suggested, and also the tax rate seemed slightly higher, so maybe just a couple of comments there would help as well.

And secondly, on refining, refining reliability is something you highlighted.

I mean, it is something that certain of your peers are struggling a little bit with at the moment, especially in the U.S..

Can you tell us how you have improved that and how sustainable that improvement is?

Could you go back through the questions you're asking on TNK (multiple speakers) part of it, but I did not get all of it.

The first one was just net revenues.

It would be useful if you had a net revenue number for the period that you're reporting here.

And then the second point was the minority charge of minus 1 at million (ph) seems significantly lower than I would've expected, given that in the first six months of this year, you were on a sort of like-for-like basis talking about a minority shareholders' interest of minus 32 million.

SO just maybe some explanation of why the difference there.

And the tax rate also appears to be somewhat higher in that the first -- in this month as opposed to the six months at the beginning of the year, seems to have gone up from something like 16 to 17 percent, to something north of 20 percent?

I think -- we have 33 days of data here.

It is estimated data and we have run a validation model on it, so we feel confident that it is accurate within the bounds of our capability of sorting it out today.

But specific issues, with respect to minorities charge and the tax rate and the wobbles around that on this 33 day period;

I think rather than try to explain it, I would prefer that we wait until we have more data and more track record and we can come up with a coherent story.

As far as revenues go, this is TNK BP number, and I'd prefer not to quote it, not because I'm unwilling to, but this is our results, this is the way it comes into our results, and that's what we're talking about today.

(indiscernible) not aware that there has been a program of buying out the minority (indiscernible) TNK BP subsidiaries, so it would be reasonable to suspect for any given level of performance (indiscernible) downward trend in the (inaudible) minority to move forward.

As regards the second part of your question, Rod, on refinery reliability and what happened there to give us that improving trend -- I think the answer is obviously (indiscernible) a very conscious strategy of focusing on what is important, in terms of driving (indiscernible).

You've heard us talk about gross margins over the last 12-15 months and our focus on that, and I think that has helped to drive into the business a greater realization at all levels of what the real levers are to improving performance in this area.

And I think one of the consequences of that, we are beginning to see through some of these metrics.

There are others and we do look to see (indiscernible) others as I mentioned in February we might share with you moving forward to help you in forecasting what we realize is quite a difficult to forecast sometimes half of it's business.

So it's really just basic good old driving underlying performance improving the business by using the right metrics.

And sustainability?

We would like to think good, clearly, but only the future will tell on that one.

But clearly, we're encouraged by the track record we've built up over the last two years.

Going back to the U.S., Tyler Dann, Banc of America.

Fergus and Byron, thanks for taking the time today.

I have three areas of questions; firstly related to capital spending, second related to divestitures and thirdly related to potential buyback.

On CapX, I wanted to see in the rest of the world E&P capital spending for the third quarter exactly what you had used for TNK BP investments since it looks as if for the nine months we are coming up, if I subtract that 3.25 billion from the 12.849b, I get about 9.6b, which would imply that if you're going to the below the 9.8-10.2 billion indicated range, then you would need to be spending not very much money in the fourth quarter.

SO I wanted to know that the number for TNK BP there.

Secondly on the divestitures, what dollar amount remains to be closed throughout the remainder of 2003 and, in terms of the amount of dollars sold close to date outside of the E&P business?

And finally on the buyback potential, could you please walk through in getting to your decision that you would likely not be buying back more shares at this level, what type of forecast I guess would you be using for oil prices etc. in order to arrive at that conclusion?

(indiscernible) taking the accounting question.

It sounds like maybe we need another seminar on TNK BP accounting.

But of course, the key point is the capital spending within TNK BP is not shown in our financial statements because it is a joint venture, and therefore, we do not include that capital spending within our numbers.

You did have a rest of the world.

In a note A on page 18, it says included in the investment in the joint venture, so I'm curious -- is it the $3.25 billion, or is there an additional number associated with that assumed or something like that?

Talking about capital spending, I was referring to organic spend, not the inorganic step that we have taken.

So hopefully, that relieves you of concerns that we're going to stop spending capital in the fourth quarter of this year.

As far as disposals go, we have completed, as I said, $5 billion worth of disposals year to date.

We have approximately $1 billion to go.

Those are all on track and I feel very confident about the $6 billion delivery for the year.

Of that, the mix is a little bit more than $1 billion in other businesses, but approaching $5 billion from the upstream.

And the biggest contributor to the fourth quarter would be the completion of the sale to Stadt (ph) Oil of our interest in Sala (ph) in Algeria.

As far as buybacks go, next year will be next year.

We have a number of things, as I indicated in my remarks, which are impacting the view in the fourth quarter.

We have this once-off on Slavneft.

We're confident now that it is going to occur in the fourth quarter.

We feel the commitment to our employees to top up the funded pension plans, and you add those two together and it is approaching $3 billion.

The fourth quarter also has, if you look at the $9.5 billion of capital spent to date, and the indicator is that although we're going to fall below $14 billion on an annualized basis, it tends as it normally is to be back-end loaded.

So we're having a heavy quarter in capital spending, and we also have some peculiarities in the timings of the tax payments over the fourth quarter.

And all of those will tend to drive our gearing rate up as we go into 2004.

At that stage with these once-offs behind us, we will be able to better assess what the environment in 2004 looks like.

And if we are facing a period of substantial surplus cash flow, because the environment is as attractive as it is so far this year, then certainly buybacks will feature very high in the considerations of the board.

Okay, thank you.

(indiscernible)

I have several questions, one regarding TNK.

You say that during third quarter, TNK BP managed to export 78 percent of its production through crude and (indiscernible).

Could you give us the splits between crude and oil products, and could you tell us if you did something particular to the third quarter, or it is something that is sustainable to be achieved by the new joint venture?

Secondly, could you give us a split between refining and distribution results in the refining and marketing division?

And also, we're getting acquisition amortization in the E&P division.

It seems to me that you were on the rhythm of amortization of $400 million.

Now, we are below 300.

Is that something recurrent (indiscernible)?

Thank you very much.

As far as TNK BP goes, the 78 percent was made up of about 60 percent of crude exports and 18 percent of product exports.

And if I look back at the first half of the year, it was a similar sort of number of product imports, and so it is additional crude imports -- exports that have driven that number.

It is important not to overreact to the ability to get crude and products out of Russia during this particular period, because there are some very strong seasonal factors which appear to drive not only the ability to export, but also indirectly drive domestic products.

During the presentation that was made by Sarah, there were a number of slides shown which pointed to the cyclicality of domestic prices in Russia.

In particular, slide 448 that Thane Gustavson (ph) showed.

As Russia goes into the winter, all of the main routes to export, both crude and products, whether it is by pipeline or by barge or by truck or by rail -- all of these become more difficult to achieve.

So you end up being able to export less product in aggregate; that creates more product and more crude that is contained within Russia itself, and therefore creates downward pressure on prices.

So you end up with a double impact positively in the summer months and it rolls the other way during the winter.

How it will evolve this winter, we can only speculate.

But if you look at the last several winters, that is indeed what happened.

If I could just take your other two questions.

On the refining versus marketing split in the third quarter, it splits $481 million in refining and $479 million in marketing.

And just to save your follow-up question, the above the line charge of 123 million for environmental remediation that was taken in the quarter was allocated $28 million to refining and 95 to marketing.

Your final question -- acquisition amortization -- I think you asked the question of -- would the fall below $3 million in the upstream be sustainable moving forward?

The answer is yes.

In prior periods over the last year or so has been tended to be distorted by some write-offs. there were some in Q2, there were some in Q3 of last year.

But if you strip those out, there has in fact also been an underlying declining trend in acquisition amortization, and of course that's because a lot of the purchase price premium on ARCO is of course being depreciated away on a unit of production basis, and that number has been coming down fairly steadily over the last two years.

And so I think it is fair to say that in the absence of any further impairment charges, the $300 million number is a sustainable number going forward.

Does that answer your question?

Yes thank you very much.

But regarding the market, could you give me the number for the marketing (indiscernible) 497?

Prior to the -- that's after the above the line charge (indiscernible) (multiple speakers).

Back to the U.S. -- Mike Mayer, Prudential.

I had three short questions.

First as I read the press release, I believe it said that your share of TNK BP was included in the E&P segment.

Does that mean that the downstream earnings of that joint venture were included in the upstream?

Second, could you break down the $123 million one-off charge between the various geographic segments for us so we could have a base to forecast forward?

And third, could you give us your production guidance for the fourth quarter, assuming no further acquisitions or divestments?

Thank you.

Okay.

On -- let's take your second question first.

The $123 million, all of that is in the United States.

So simple geographic boundary there.

Your first question about TNK BP, we have felt that because of the close integration of the refineries with TNK's upstream business in a way that is uniquely Russian in order to achieve higher value for the crude production, it was appropriate to -- at least at this time -- to create TNK BP as an upstream entity and try not to split it into its component parts.

So at least for now, you will see all of the TNK BP results showing up in the E&P segment.

It's something we will look at over the course of time, but we believe it is appropriate representation at this time.

Production -- what you will see in Q4 is the overall impact of 90 days worth of TNK BP.

So it will clearly be greatly accretive to overall production volumes, since we only saw a third of that in the third quarter of this year.

Our underlying production, we continue to believe will fall between the zero to 3 percent range as we indicated at the start of the year.

One follow-up if I may.

I should have asked it before.

The $45 million one-off in gas and power -- was that all U.S., or how did that break out?

18 in the U.S., 23 in the rest of Europe, 1 in the UK and 3 in the rest of the world.

Thank you.

Coming back to Europe -- J.J. Traynor.

Question about the environmental remediation provisions.

Can I just clarify -- are you moving to a new standard when you are making those definitions.

Is this a BP standard, is this something driven by regulators?

And have you been through that process in the upstream -- do you think you are over-provisioned on the provisions in the upstream for these sorts of liabilities?

And as an unrelated question, I am interested to see you're still taking special items on the Veba several -- a lot of time into that acquisition.

Is everything okay with the Veba integration process?

Let me deal with the third one first.

On Veba, as is true with almost all of our acquisitions, we go through a period of restructuring those businesses as we integrate them into BP.

We have done this with Amoco, we've done this with ARCO, we've done it with Burmah Castrol; we're doing it with Veba.

What we think that that once-off integration process is appropriately shown as a special item.

In the case of Veba, we're nearing the end of that process, and there would be no special charges associated with Veba in 2004.

So we will clear the decks on that integration process as we have with the other acquisitions and mergers after an appropriate time in the past.

As far as the standard that we have established, J.J., this indeed is -- we have looked across what we were doing in the refining and marketing area and what we were doing in the OB&C area, in particular, the legacy mining liabilities that we acquired when we purchased ARCO.

And we felt as though there needed to be a single methodology applied across the piece and we chose a more conservative process to make those adjustments, which has led to the once-off charge.

There's nothing that was demanded of us by any regulatory body.

It was a decision taken by basically myself and the control staff within BP and our external auditors.

And as far as -- where do the liabilities show up in the upstream -- of course, there is a special tag there of decommissioning which we associate on a unit-by-unit basis, that we take the full charge upfront when we bring a field into operation.

So it is captured for the upstream in the decommissioning charges.

Can I clarify -- have you been adding to those provisions, or does the impact of better technology mean that there is actually (indiscernible) flowback (ph) from that provisioning?

All of this information is available in our annual report.

We will take a look and see if we can come up with an answer to that over the course of this conversation.

If not, the IR staff will get back to you, J.J.

But it is on the record, and I just don't have the numbers in front of me at this moment.

We'll come back to you off-line on that. back to the U.S. -- Fadel Gheit from Oppenheimer.

Good afternoon.

A couple of questions, one upstream and one downstream.

Using the numbers that you published, volume and realization and margins, you are showing about a $300 million shortfall in upstream and 500 million in the downstream.

Can you explain why?

You'll have heard Byron make reference in his remarks to a rise in depreciation.

I think it came out in the answer to one of the previous questions, and that is certainly an element in the (indiscernible).

Another element of course will be foreign exchange effect, and I suspect that some of those two factors, Fadel, would probably more than close that gap actually.

If you would like to call us offline, we will walk through your model and we'll se if we can identify (multiple speakers) relative to your own expectations are, but I would certainly suspect (multiple speakers).

But you don't see any unit cost increase?

You do not see any unit cost increase? (MULTIPLE SPEAKERS).

(indiscernible) from Sanford Bernstein -- Neil, are you there?

I think you're having problems hearing some answers here, so I will try and give you a break while you answer my questions.

But first of all, three questions, one on disposals.

Could you go over the disposals this year, where they actually were in the upstream?

Then secondly, thinking about disposals going into next year, obviously to try and keep the cash in and cash out balance that you show on your charts and line, you need a certain amount of disposals next year as well, presuming we don't have oil prices at the current level.

I wonder if you could just walk through any guidance on disposal levels next year and where they may be coming from?

And then the second major question is on CapX guidance into next year.

You said you were potentially going to be at the low end for this year.

I just wanted to know what the guidance level is for next year, and if any CapX has moved from this year originally into next year?

Thanks.

You have asked for I think a laundry list of disposals.

We've disclosed those on a quarterly basis.

As I indicated earlier, they tend to be primarily upstream-related disposals, and they began the start of the year with 40s and a number of mature U.S. projects, and have gone and incorporated across a global portfolio of noncore and oftentimes mature assets.

We have sold a few things in the downstream.

In chemicals, we've finally finished exiting the Castrol specialties area that we inherited as a consequence of the Burmah Castrol acquisition and was not a good fit into our own businesses.

But there have been sales across the piece, but as I said, primarily in the upstream and I gave an indication that in the fourth quarter, there would be a material contribution from the sale of our remaining 50 percent sale to Stadt (ph) Oil in Algeria.

One thing that I also referenced, although I didn't reference it as a specific disposal, is the sale of our interest in (indiscernible) Prima Coal (ph) in Indonesia and a number of other small items.

For next year, we will not be involved in a disposal program of this scale.

We have cleaned up the majority of the bits of the upstream portfolio that we did not feel was strategic for the future.

There is always some house cleaning, as indeed there is a need for some continued house cleaning in the market-facing businesses.

But I will not guide you to a particular number.

This is something we'll share with you at the start of 2004.

But I can point you in a direction that is considerably less than what we have experienced this year.

And as far as capital goes, John Browne when he made the strategic presentation back in February, indicated that this would be a peaking period in capital spending for the group, and that it would tend to move down from here going forward.

And, no, there are no material items that are slipping from 2003 to 2004.

This is merely an optimization of the spend that we are focusing this year.

Back to the U.S. -- Al Anton (ph) from (indiscernible).

I have two questions.

We talked a little bit about Angola and your other operated block is this deepwater block 31 where you have had three rather quick discoveries.

And I wonder what your plans are there for stepping out those discoveries or drilling additional features?

And can you just comment on the general outlook for possible development of the block?

And secondly, I think the Bible says that a man that is without profit in his own country, and if you look at both your refining and marketing in petrochemicals results the UK where losses are both for the quarter and for the nine months, and I wonder if you could tell me if there are any special factors in the UK downstream, how it's divided between the refining and marketing?

And in petrochemicals, are you at a feed stocks (ph) disadvantage, or is there any special problem there versus the rest of Europe or other areas?

On Angola, there's nothing we can say at this stage.

It is very early days with respect to developing decisions around the development of the block, and I can make no comment on it.

In the UK, there are always some additional features, because the United Kingdom tends to pick up some of the overhead costs associated with the running of the various segments.

So this tends to impact negatively on UK results.

There is nothing fundamental about the business operations here in the UK, as opposed to elsewhere in Europe.

I thought the UK downstream was run out of Brussels?

There are still costs associated with the running of the UK business here in the UK.

So the costs are loaded on the UK?

(indiscernible) stock exchange announcement in the UK about those charges taken above the line, which makes the third quarter look a little weaker on (indiscernible) line basis.

It actually was.

Coming back to the UK -- Matthew (indiscernible) from Goldman, Sachs

My question is on the statements that Byron made earlier that have been reported on the newswires with respect to thinking about oil prices and how you're running the business on the basis of the reality of the world around you.

I was wondering if you could comment on the oil prices you're using in your medium-range planning?

My comment was a comment with respect to a question that was asked about mid-cycle prices and how we were running our business with respect to mid-cycle.

If all of you are more familiar than the individual who asked me that question, that John made very clear back in February that we're no longer to tie ourselves to a reconciliation of returns or any other features associated with a standardized set of assumptions.

And my remark was that we're running this company with reflection to the world around us, the capability of generating cash in this particular world.

We do, however, have a financial framework that underpins decisions on how we invest and the overall cost structure of the group.

It underpins the ability of BP to pay dividends and to finance our debt.

And we clearly build that framework at much more conservative prices than we see today.

It is because of that that we can say that when times are good like they have been so far in 2003, it gives us the luxury without undermining our ongoing business, our ongoing obligations to our shareholders, our ongoing obligations to those who lend us money, our ongoing obligations to building the portfolio through organic capital expenditure, that in that sort of world, we have options to acquire assets to do things like to fund pensions, which is not a required obligation, but one that we feel it is appropriate for a firm of our scale, and to buyback shares.

And so we run this company fundamentally at lower prices than we see today.

But it is in reflection of the world around us that we take our decisions on what to do with the surplus cash.

(indiscernible), Morgan Stanley.

Hello.

A few simple questions.

First of all, going back to TNK, can you give us an indication of the frequency with which the cash dividend would be received from TNK?

Will it be quarterly, biannually or annually?

Secondly, I didn't hear your answer to an earlier question on the tax guidance going forward for the group.

And finally, could you just remind us what the Slavneft outlook levels are at the present?

Thank you.

It will be up to the TNK BP board to decide the frequency of their dividending policy.

And I think we just need to wait and see how that works out.

They have not made a specific statement on the regularity of dividends, but since we are a 50 percent owner, we would want the dividends to be appropriately paced and not accumulate on an annualized basis, as I would suspect.

But that is, as I said, a decisions for their Board.

On tax guidance for the year, the effective rate for the third quarter for those of you with sharp pencils, you have seen we have used 35 percent.

This is up from the 34 percent of that we used in the first two quarters of this year.

As prices for oil and gas have remained high over the year, because our marginal rate is higher than the effective rate, it is closer to 40 percent on the margin than 34 percent.

This has created a little bit of upward pull on the effective rate.

And the way in which we handle this is to look out at the end of the year and then adjust accordingly on a quarter-by-quarter basis, so that we are coming in at our estimated tax level.

And we have decided in Q3 that 34 is a bit low.

It will be 34 and a bit, and that it was appropriate to up the charge slightly in the third quarter, and then we will zero in on it in 4Q.

We don't have any specific Slavneft production number that I can relate to you at this time.

I think it would be fair to say that production growth this year is running at a similar level to last year's 13 percent, maybe even slightly higher.

But I don't think it's appropriate for us to comment on that until the transaction closes, which we hope to be later on this years, as Byron mentioned earlier.

Neil Morton (ph), DKW.

Good afternoon.

Just a couple of quick things.

Firstly, coming back to that very strong profit contribution from TNK BP in the month of September, you highlighted potentially seasonal factors.

Also mentioned the possibility of reconciliation due to different timing of closures in the accounts.

I just wondered whether there was any element potentially of callback in Q3 of profit that perhaps should have been there in the first half.

And secondly on the BTC pipeline, you mentioned that you saw early startup -- or startup in early 2005, but I think you have been documented problems in early drilling of wells on ECG (ph).

I wonder whether there was a risk of having a brand-new pipeline in 2005, but no oil to go in it?

TNK BP September -- to the best of our knowledge, this is appropriately reflective of 3Q results themselves, and there are no - there is no clawback (ph).

This is a clean number as best that we can estimate it.

Although as you referenced, there are a number of seasonal factors, but not a number of quarter to quarter factors that are influencing the result.

B to C (ph) continued to believe that there will be a completed line in 2005, and we don't see any risk to the oil being there from the Azerbaijan fields come the day the pipeline is ready to accept it.

That is great.

Thank you.

Ron Oster, A.G. Edwards.

Thanks, guys.

Question for you on your U.S. gas production.

We are showing it came in a little bit below our expectations.

It was down 4 percent sequentially and 13 percent year-over-year.

And I know some of this is related to divestments.

Can you quantify the impact of divestments versus natural fuel decline (ph)?

And was there any hurricane impact in the quarter, and if you could give us any guidance going forward?

And one other question regarding your Na Kika project.

Any update on first production and startup rates from that project?

Thank you.

Perhaps I could start off, Ron, and give you the numbers in terms of the divestments impact.

Relative to the third quarter of last year, it was just under 300 Mcf (ph) of divestment impact.

So if you add that back, you end up with a decline (ph) rate of about 4 percent, which is not out of line with our expectations.

In Na Kika, we have penciled in for early 1Q 2004.

I know -- I suggested it might be in the area, that will be great news if it is on stream earlier.

But in our plans, we have assumed early 2004, early in the first quarter.

Well, it sounds like there are no more questions.

I would just like to thank everybody for listening.

I do realize there's been quite a lot of new disclosure in this quarter's results, particularly on TNK BP.

We've disclosed rather more than we are required to by UK accounting standards.

The I.R. team remains very happy to walk anybody through who would like to go through in any more detail how each line item TNK BP shows up in the BP group figures.

With that, I'd just like to say thanks.

We're always ready to take your calls and speak to you again in a quarter's time.

I'd like to add my thanks to Fergus'.