英國石油 (BP) 2005 Q1 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.

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

I would like to welcome you to BP's first-quarter 2005 conference call.

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

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

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

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

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

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

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

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

Actual results may differ from these plans or forecasts for a number of reasons such as those noted on this slide.

Now over to Byron.

Thank you, Fergus.

As you know, this is our first quarter under International Financial Reporting Standards or IFRS.

All prior year comparative data presented today and contained in our stock exchange announcement have been restated for IFRS and the other changes I described in our technical briefing last month as detailed on our investor website.

Before discussing the financials, I will quickly review price and margin conditions which were slightly better than in the prior quarter and up significantly on the first quarter of 2004.

Our average crude oil realization in 1Q was more than $43 per barrel, 39% higher than in the first quarter of last year.

Oil prices continue to be supported by strong growth in demand and limited spare global production capacity.

Our gas realization in 1Q rose less, up 12% compared with a year ago.

These higher oil and gas prices led to a 27% year on year increase in our overall average hydrocarbon realization.

The industry indicator refining margin was up 21% compared with a year earlier.

Our own refining margin continued to benefit from wide light/heavy differentials.

Although not shown, retail marketing margins were under extreme competitive pressure during most of the quarter.

Margins also strengthened across our petrochemicals businesses which are now split between a refining and marketing segment and other businesses in corporate.

These higher prices in margins contributed to the record quarterly earnings and cash flow we announced this morning.

Our 1Q replacement cost profit of $5.5 billion was 29% higher than in the first quarter of 2004.

On a per-share basis, the increase was 33%, reflecting the effect of share buybacks over the past year.

Our profit, including inventory gains which we previously referred to as historical cost profit, was up 34% to $6.6 billion.

Our 1Q earnings in both periods included significant gains related to nonoperating items.

I will describe these in a moment.

Excluding nonoperating items, our replacement cost profit per share was up 46% year on year.

Operating cash flow rose 34% compared with a year ago to $9.4 billion.

The $0.85 per-share dividend announced today, which will be paid in June, is up 26% compared with a year ago.

Our first-quarter earnings included a $535 million post tax gain from nonoperating items.

These included significant disposal gains mainly related to the sale of our interests in the Ormen Lange field in Norway.

This was partly offset by charges related to asset impairments and mark-to-market IFRS accounting impacts for embedded derivatives.

In the first quarter of last year, the somewhat higher gain from nonoperating items relates mainly to the sale of our successful investments in Petro China and Sinopec.

Our stock exchange announcement provides further details of all these items.

This chart shows the main elements driving the 29% improvement in our 1Q replacement cost profit from $4.3 billion last year to $5.5 billion in 2005.

Our gain from nonoperating items was nearly $250 million lower in 1Q '05 than 1Q '04.

Higher prices and margins added $1.8 billion year on year.

Two-thirds of this was due to higher oil and gas prices and the remaining one-third to higher margins in the customer facing businesses.

The weaker dollar had a relatively minor negative effect compared with the first quarter of 2004, around $50 million.

Acquisition and divestment activity decreased our 1Q result by around $50 million.

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

The $50 million year on year impact of higher depreciation, depletion and amortization was also mainly in E&P.

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

Other factors included a number of items.

We saw benefits from higher upstream production volumes, stronger supply optimization performance and refining, and improved performance in lubricants and business to business marketing.

We also saw higher cost for new field start-ups, well work, repairs related to last year's Temsah blowout and Hurricane Ivan, higher refining turnaround activity and the settlement of environmental litigation in California.

Our effective tax rate increased by around 1% from 31% last year to 32% in 1Q '05.

This represents our current view of the effective tax rate for the year, including benefits from the release of provisions for previous years.

The overall impact of these factors was a net reduction of around $200 million.

Our underlying business performance remains on track with the strategies we discussed in February.

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

Our E&P result increased more than 50% to a record $6.5 billion.

This included a $780 million net gain from nonoperating items, mainly related to the Ormen Lange disposal and IFRS mark-to-market accounting of embedded derivatives.

Excluding nonoperating items, the E&P result was 35% higher than in 1Q '04.

This reflects higher realizations, as well as increased production in TNK-BP and new fields in the deepwater Gulf of Mexico, which more than offset declines in other areas.

Production in the quarter was up 2% on 1Q '04, and we remain on track to achieve our previously indicated range of 4.1 to 4.2 million barrels per day of oil equivalent for the year.

As we said in February, this level is estimated at our $20 per barrel long-term planning assumption.

If prices remain at current levels, volumes from production sharing contracts would be about 50,000 barrels per day lower.

TNK-BP contributed nearly $400 million to our 1Q '05 result, around twice as much as last year.

TNK-BP is in the process of reviewing certain tax notifications received from the Russian authorities relating to 2001.

It is too early to predict the outcome.

However, we do have extensive indemnities from our co-joint ventures in respect of historic tax liabilities.

Our refining and marketing result of $1.4 billion was up 54% on 1Q '04.

The increase was 34% excluding nonoperating items.

This reflects higher margins and supply optimization benefits in refining and stronger results in our business to business activities which now include Aromatics & Acetyls.

These more than offset the impact of lower retail marketing margins.

Refining available during the quarter remains strong.

As you are aware, in March we experienced an explosion in fire at our Texas City refinery.

Investigations are continuing.

It is too early to assess the full financial impact of this incident.

Our Gas, Power, Renewables result more than doubled year on year to $400 million in 1Q '05.

This includes $105 million of nonoperating items related to disposals and embedded derivatives.

Excluding these nonoperating items, the underlying improvement was closer to 50% driven mainly by higher margins for natural gas liquids in North America.

Results in other businesses and corporate or OB&C declined from $1.1 billion in 1Q '04 to $200 million in 1Q '05.

Last year's result was dominated by the large nonoperating gain from the sale of our Petro China and Sinopec shares.

Excluding nonoperating items, this quarter's result reflects a significant improvement in Olefins & Derivatives from a small underlying profit last year to $380 million this year.

We have provided further details on our Olefins & Derivatives result in Note 10 of our stock exchange announcement.

In addition, the OB&C improvement reflects a lower net corporate charge, although we still expect the full-year result to be in line with the guidance I provided last month.

In addition to producing strong financial results, we achieved a number of strategic milestones in the first quarter.

Exploration highlights included our fifth and sixth discoveries in Angola Block 31.

We were also awarded three blocks in Algeria's sixth international licensing round.

We started up three major projects in E&P -- Mad Dog in the U.S.

Gulf of Mexico, Azeri in Azerbaijan, and Clair in the UK North Sea.

All our major projects are on track.

With respect to the deepwater Gulf of Mexico, the Atlantis platform is in route from the Korean shipyard to Texas, and the Thunder Horse integrated hull and topsides is now on location offshore.

In addition, we sanctioned the Tangguh LNG project in Indonesia and the development of the Sakkara gasfield in Egypt.

In March we signed a joint venture contract with Sinopec to build a worldscale acetic acid plant in Nanjing China.

In Shanghai we started up the SECCO joint venture petrochemicals complex ahead of schedule.

We have now established our Olefins & Derivatives business, Innovene, as a separate legal entity within BP.

Preparations for the sale of Innovene are proceeding well for execution in the fourth quarter of the year, probably by way of an IPO subject to market conditions and necessary approvals.

Returning to the financial results, this slide compares our sources and uses of cash in the first quarter of 2004 and 2005.

Operating cash flow increased to $9.4 billion.

Disposals provided a further $1.3 billion in the quarter.

Uses of cash remain consistent with our strategic intent.

Organic capital expenditures were just under $3 billion, slightly less than last year and on track for our full-year estimate of around $14 billion.

Total distributions to shareholders, including dividends and buybacks, rose $1.1 billion to nearly $3.8 million.

Our pretax cash return in the first quarter was 37%.

This is the same as in 4Q '04 and up from 30% a year ago.

This represents progressively stronger cash generation on a growing capital base.

The data shown are based on actual prices and margins.

As best we can estimate, our cash generation is on track with our strategic indicator to increase underlying cash returns by 2% over the 2003 to 2006 period based on price and margin assumptions that are substantially lower than those today.

Our net debt ratio fell from 22% at year-end to 18% at the end of 1Q, reflecting the strong 1Q cash flows I just mentioned.

In the current price environment, we expect gearing to remain near the lower end of our 20 to 30% band.

These charts compare shareholder distributions for the past three years with those in 1Q '05 shown on a proportionment scale.

Our first-quarter distributions included dividends of $1.8 billion reflecting the step change in the dividend we announced in February.

We also bought back $2 billion of shares in the quarter.

Since the start of the second quarter, we have already purchased another $500 million of shares under our closed period buyback program.

Continuation of the current environment would support ongoing substantial share buybacks consistent with our financial framework and distribution policy.

That concludes my review of the results.

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

(OPERATOR INSTRUCTIONS).

Neil Perry, Morgan Stanley.

Two questions.

One upstream, one downstream.

On the nontax cost in the upstream, it appeared that there is a slight decline in nontax cost in the first quarter versus the fourth quarter.

Is there some sort of phasing thing going on there?

Should we expect the cost to increase as we progress through the year?

And secondly, on the downstream, if you look at your indicator margins and you look at what you are making in Refining explicitly as opposed to Refining & Marketing, it would appear that you are almost at a record still in the fourth quarter in the Refining side of the business.

Can you talk about optimization?

Is that just a function of the wide light/heavy differential, or is this something more sustainable that you are doing in there independent of the macroenvironment that might lead to a new relationship between what you earn in Refining and your indicator margins?

I will take the downstream question first.

This has been a fantastic period of time in refining.

We believe that as a Company we are extremely well positioned for it.

We have got refining margins driven by lots of demand, pretty much across the world.

And then, increasingly the marginal barrel of product of crude oil is sourced as heavier barrel.

So those with refining capability to upgrade those types of crude oil will disproportionately benefit.

And as a Company with that upgrading capacity and in particular having a very strong position in the United States, we feel we are in an extremely strong position.

The Global Indicator Margin as we have said a number of times in the past is indicative of a general refining margin and does not necessarily represent BP's own capabilities in a range of different situations.

Sometimes it tends to overstate our capability.

Sometimes it tends to understate our capability.

But as a Company positioned in today's environment with the very wide light/heavy differentials, you should expect us to continue to see very very strong refining results.

Turning to your question about upstream costs in the quarter, I think there were three things here.

The first thing is that we did stress in the fourth quarter last year there were some unusually high costs in that quarter associated many of them with Hurricane Ivan and the U.S.

Gulf of Mexico and the Temsah blowout, nonoperated blowout in Egypt.

The second thing is, of course, exploration write-off which typically is higher in the fourth quarter of the year, and as you can see from the release, it is back to the more normal first-quarter level.

And the third point is there is a small element of quarterly phasing.

That is always a (inaudible) to variability around that.

But that's probably the smallest of the three effects.

We have also seen some of that in the corporate cost as you know.

I suppose the most important point is we do feel that we are capturing the upside of the strong environment, and that the first quarter is showing that perhaps more clearly than the fourth quarter did.

Now turning to the United States, we've got Robert Kessler from Simmons & Co..

Robert, are you there?

Good afternoon, gentlemen.

I wanted to see if you could go through an update on your business in Azerbaijan.

In particular, any comments you could provide in regards to the level of production from ACG currently?

And then just a general discussion around the progress of the BTC line.

And industry articles have suggested that you're going to start the line-fill next month I believe with output coming out in September at the other end.

I'm wondering if that is a reasonable quote there.

And then given that you're just about complete with the line now, what is your revised all-in cost estimate?

Is it the $4 billion number that is being quoted a good number as well?

The general summary about our position in Azerbaijan is it remains on track with the milestones that Tony Hayward took you through during the course of a number of different interactions with the investment community.

We have outlined more than a year ago a profile of different projects, and this is one of the important ones, but there are many others.

And indicated that these where the projects that needed to be tracked to see how production was going to respond in our new profit centers since new projects are, indeed, the primary driver of the ramp-ups.

Both with respect to the fields in Azerbaijan and with respect to BTC pipeline, we remain on target with our indications.

The indication with respect to oil flowing out of BTC was that it would occur sometime before the end of 2005, and I like to remain positioned at that as opposed to speaking to a specific month.

As far as a cost estimate, as you indicated, $4 billion remains a best estimate of the all-out cost.

Just one point of detail you raised, current production levels over 50,000 barrels a day from ACG, and we got first revenue oil only late in the quarter on the 3rd of March.

So that project is, as Byron says, going quite well.

Coming back to the UK, could we go to Tim Whitaker at Lehman Brothers.

Good afternoon.

I have two questions.

Firstly on the UK downstream business and after your segmentation adjustments, it looks to be somewhat unprofitable.

Is this reflecting underlying marketing profitability, or are there some other factors there?

And perhaps you could allude to what the future of this business might be.

It seems to have been unprofitable for some while.

And secondly, in your annual report, you disclosed five categories of trading profit.

I wonder if you could give the corresponding figures for Q1?

Well, Tim, I'm going to start with the second one first.

We treat our integrated supply and trading operations as supportive of the activities within the business segments.

That it is not possible to disintegrate those from the underlying operations.

It is the reason you don't find a supply and trading segment reported as part of BP's results.

It is because we find ourselves incapable of actually segmenting it out since it is so intertwined with the underlying business.

On an annual basis, we are required for statutory purposes to go through and attempt to measure some of the instruments that are used in that process.

But that is something that we only do on an annual basis.

And we feel even having done that, it does not truly reflect those activities since we would not be undertaking them did we not have the business presence in the Refining & Marketing, Petrochemicals, Gas, Power, Renewables and Exploration & Production segments.

As far as UK downstream in the United Kingdom, it is very difficult to sort out the UK segment actually in all of the UK segment and in actually all of our business segments because it is the headquarters of not only the group, but it is the center of the corporate activities for each of the business segments.

And so you will typically see a lot of volatility in the UK as corporate charge-outs oscillate up and down during the course of the various quarters.

I would not take this number to be representative of the underlying profitability of our operations in the United Kingdom in Refining & Marketing segment.

And in specific respect to the first-quarter number which you're looking at and which I think you would agree looks like an unusually large negative, there are two big things going on there.

The one is the big squeeze in retail margins that we experienced, and second there was a significant turnaround at the Coryton refinery in the UK in the first quarter which also affected that result.

Moving on to John Rigby at UBS.

Two questions.

One, could you take the opportunity just to update us as to the meetings between Lord Browne and President Putin on Friday about the communications between yourselves and the Russian government and how that reflects TNK-BP?

And the second is, I was pleasantly surprised I guess on the Olefins & Derivatives number that is now within OB&C.

My calculation suggested it is probably up about 150% sequentially.

Is that correct, and what are the moving parts that are driving such a big increase?

I know the Olefins & Derivatives market has improved, but not by that much I don't think.

John, excuse me, I will respond to the first question about Lord Browne's meeting with President Putin.

Obviously there were private and public parts of that, and I won't speak to the private components.

But this was an opportunity for the two men to check in with respect to the targets that President Putin had given us at the time of establishing the TNK-BP joint venture.

There were four things that were talked about at that time and that BP would be able to provide the capability of increasing production to add technology, to improve the management and the governance of the Company, move it towards world-class, and to act as a good Russian citizen with respect to all of its activities in the country.

We feel that we have made significant progress in all of these categories.

You can see the substantial production ramp-up.

You can see the technology we are bringing that underpins that.

We believe we have made incredible strides with respect to bringing the types of standards that we have in all of our operations in the world to TNK-BP.

And in the course of doing that, we have met all of the obligations of being a Russian company and in our case a visitor to that country.

So we feel very good about what we have accomplished.

I think that the comments that President Putin made afterwards spoke to his comfort in what we as a company are accomplishing there.

Turning to the Olefins & Derivatives result, there are four things there.

You're absolutely right, margins did improve; but you're also right, that was not the full story.

The other things were there were some cost reductions following the big restructuring which we announced late last year.

There was also a full quarter of contribution from the Solvay business which required late last year, and lastly you'll remember that this business, Innovene, does include some refining in the UK and in France.

And in France in particular, there was improvement in refining margins.

And that all came despite the fact that we did incur some startup costs as the SECCO petrochemical plant in Shanghai was started up.

So it was all in all an encouraging start to the year for Innovene.

John, since you raised the question about the meeting with President Putin, I think I will take the opportunity to address a question that may be on some people's minds with respect to the tax notification which in summary totaled about $1 billion that was levied against TNK-BP with respect to 2001 tax obligations.

This is something that as we have indicated in our stock exchange announcement relates to prior periods.

It relates to a period prior to TNK-BP becoming an entity.

We as a Company have extensive indemnifications with respect to prior period obligations with our joint venture partners.

I would also say that this is a tax notification.

It is not a tax claim, it is not a tax demand, it is a tax notification.

And in that context, it is not materially different than exists in the United Kingdom, the United States, pretty much any country in the world, where fiscal officials raise questions about interpretation.

Notification is given.

Inevitably these are sorted out, usually at amounts much lower than the original notification.

So this is progressing.

It is still at the early stages to assess it, but we feel this is normal course of business and in no way are particularly bothered that this would undermine the capability of BP in the form of TNK-BP to continue to grow our presence in the Russian Federation.

And now Colin Smith from CSFB.

Two questions, please.

Just, first of all, on Texas City which happened at the end of the quarter, I wonder if you could just give us a view on how that might affect things going forward?

And the second thing was, just on the tax notification if it turns into a more significant claim, can you be a little bit more clear about the mechanism by which you would recoup cost?

Does TNK-BP have to pay them first and then you get them back from the partners, or how would that work?

With respect to Texas City, we have taken a very small charge in the first quarter relating to the equipment that was damaged there writing it off.

We self-insure as a Company as we have said in the past.

So the consequences of this episode fall fully on BP's shoulders, and that is right and proper.

We have found over the course of a run of years that self-insurance has provided substantial benefits to the group, and we remain comfortable in doing that.

It is far too soon to make any assessment of what the overall liabilities associated with this particular incident would entail.

As far as the operations in Texas City itself, those particular units that were impacted by the explosion and fire remain a non-operating.

But the facility as a whole is operating, and there is very very little curtailment of production as a consequence of the incident.

It more has to do with the capability to fully exploit the units and making a higher quality gasoline.

But in general it has had very limited impact on the day to day operations at the facility post the explosion.

With respect to the tax notification, no, I don't think it is appropriate for me to go into the details of how this might sort through between the partners in the co-joint venture of TNK-BP.

Mark Iannoti from Merrill Lynch.

First of all, Byron, you sound a little bit more confident on refining than we have heard you in recent times.

Are there any circumstances where you would consider reversing the decision to include Grangemouth and Lavera in the Innovene disposal?

And secondly to Fergus.

Fergus, your trading statements historically have been really pretty good in terms of guidance on the quarter's numbers.

This quarter there were three or four things in the trading statement that did not ultimately translate into the numbers.

I'm thinking interest gains in Gas, Power and Renewables, U.S. gas realizations.

Is that just the fact that even after IFRS or do you think the trading statement is becoming a little bit complex and maybe less of a gain than it used to be when the focus was on just E&P volumes?

That was nice that you directed the second one to Fergus.

I will let him handle it, and then I may have some additional comments myself.

But with respect to Grangemouth and Lavera, the decision of where to divide up the petrochemicals and refining assets of the group in establishing Innovene was done along the lines of a strategic analysis of the sites.

It is the reason why we have actually kept the Olefins unit at Gelsenkirken as part of BP, because in that particular case we felt that it was too hard to separate it out recognizing that that is a joint venture operation with PDVSA as well.

But it was too hard to separate it out.

It was well integrated with the refinery.

On that occasion, it should appropriately stay as part of BP.

With respect to Lavera and Grangemouth, these are big petrochemical sites.

Much of the feedstock coming out of the refinery is going into support of those operations, and the more we contemplated it, the more it was clear to us that they were appropriately supportive of the Innovene petrochemicals assets there and that strategically they should go with that entity.

We are, indeed, more update about refining margins as I think everybody in the world is today.

It is a consequence of the remarks I made earlier about the demand supply equation now has the incremental barrel much lighter and in many cases much more sour than was true for an extended period of time, and that puts a premium on upgrading capabilities within the refineries.

So as long as that situation remains and it is likely to remain for a period of time anyway, as long as that remains, then refineries like the ones that BP has should do extremely well, as, indeed, should the refineries that Innovene is inheriting from BP.

Turning to the trading update, I would remind you of the purpose of the trading update.

The purpose of the trading update is as the first paragraph of it makes clear, to provide estimates regarding the revenue and trading conditions in the quarter and certain identified non-operating items.

The data is provisional, and it may differ materially from the final numbers that will be reported.

So that turned out to be more the case.

We do the best we can here, but the data is pulled together right as the quarter closes.

Most of it actually turned out to be pretty accurate.

The areas where maybe it was not as accurate as we would like, realizations in U.S. gas were slightly better than we thought as that quarter closed.

So there is about a $0.40 an Mcf difference there.

Production was pretty much as we expected.

And in terms of the non-operating items, that was also pretty much as expected.

But absolutely criticism welcomed, and we will try to make it as accurate as we can in future quarters.

The track record is not bad, but there is always scope for improvement there.

It is not obviously intended to be a preannouncement of the results.

If I could just build off Fergus' comments, we do try to do the best we can with the information that we have at the first of the month as opposed to nearer the end of the month like it is today.

And if we could close and fully assess d everything instantaneously, we would have been reporting our results well before today.

We learn as we go here, tried to incorporate the lessons.

It is our intent to provide the best advice to our investors with respect to the probable key influencers on the accounts on a particular quarter, and we will continue to do that.

There is no doubt that the transition to IFRS provided some complications associated with that.

Thanks, Bob.

Good question.

Now turning to Europe, Paschal Mangley (ph), XM (ph).

Good afternoon.

Just a question.

The first one is regarding SECCO.

Could you give us the contribution to Olefins & Derivatives of SECCO in the first quarter, and what we can expect going forward?

And secondly is regarding Acetyls & Aromatics.

Did this -- within R&M, did these activities add a similar performance to that of Olefins & Derivatives in Q1 '05?

I will speak to SECCO and have Fergus respond to your second question.

SECCO is just in the commissioning stage.

We commissioned the derivatives units early in the quarter and then the cracker itself at the backside of the March period.

So the contribution in 1Q was essentially nonexistent.

It was going through the commissioning process.

The contribution from the facility as the year goes on because it will ramp up as the year goes on, it is still in the very early stages.

It will increase.

I am not prepared to provide an estimate of how that trajectory will progress over the course of the year at the current time.

I think it is best to take a look at it again in 90 days when we actually had the opportunity to see the facility in operation pass the initial commissioning for at least a few months.

Going on to your question about the relative contributions, the Olefins & Derivatives and the Acetyls & Aromatics business, clearly we don't disclose Refining & Marketing segment performance at the subsegmental levels.

So we cannot give you a precise number for A&A, but you can see from the data that we provided at the time of the resegmentation exercise introduction of IFRS in March, some order of magnitude for its contribution, and you will see from that that is materially less than the Olefins & Derivatives number that is contained in today's stock exchange announcement.

Now going to North America, Mark Gilman from Benchmark.

A couple of things if I could.

Byron, could you clarify just a bit the comments regarding the effective tax rate, and in particular over what period the release of provisions and settlements is likely to impact the effective tax rate and say what the first quarter tax rate, effective tax rate and replacement cost might have been had it not been for that?

The second question really relates to Innovene.

I have heard references I guess in a number of places that you might be interested in retaining some interest in Innovene.

Could you clarify the Company's thinking with respect to the retention of interest going forward after an IPO later in the year?

Thank you, Mark.

As far as the effective tax rate goes, it was 32% in the first quarter.

We had indicated -- I had indicated back in March in my technical presentation that under IFRS we expected the effective tax rate in the sort of conditions that we saw in 2004 to be in the 33 to 34% range.

Obviously we're in a bit better environment than that.

So you would have expected pressures for the tax rate to go up since on the margin we're taxed at about 40%.

The releases then that we have indicated in the first quarter have about a 3% impact on the effective tax rate for the year.

We indicate our tax rate quarterly with an eye towards the rate that we are anticipating for the year.

So as we see these things, there is a smoothing that takes place.

So, Mark, I believe that the answer to the question that you have asked is, the 32% is guidance towards the effective tax rate that you will see in 2005, and it is just not a quarterly phenomenon in its own right.

As far as Innovene goes, if we progress as is our base case down the IPO track, we will be almost certainly retaining some interest in it.

This even to place a significantly less than half of the Innovene shares given the scale of the Company in its own right would be a very very large IPO.

So we will look at a range of opportunities.

We will have to evaluate the volume placed against the price we can realize for it on the day itself.

But the like most likely situation of going the IPO route would anticipate that BP would place a portion of its shares on the first count.

That, Mark, would be the standard practice.

Sorry -- just in case you are thinking that this implies an intent on the part of BP to potentially hold onto an interest over the long haul, it would be our intention to utilize the marketplace to exit from our interest in Innovene on an orderly basis, and we have no strategic intent to retain an interest in the Company.

Coming back to the UK, John Wright from Citigroup.

Just had a quick question regarding the UK oil production.

It is down quite heavy year or year, about 16% or 60,000 barrels a day.

I wonder if you can tell us how much of that is about divestments and how much decline rates?

Yes, so the question is about the first quarter of '05 relative to the first quarter of '04.

Well, in terms of that comparison, there is not much of an impact from divestments, John.

There were some weather-related operational reliability and department operated issues.

We had some problems on sheer water in the quarter which has not helped.

So I would say you're seeing a reported decline there in terms of liquids I think of about 16% and gas of 8%.

A portion of that is operational efficiency issues to do with the issues I just mentioned, rather than the decline itself.

So it's a mixture of the two factors.

It might be expected to bounce back through the quarter?

The operational efficiency would be yes, depending on how long the operational efficiency issues persist.

Moving on Neil McMahon from Bernstein.

Just a follow-up on that one and another one.

So, Fergus, what is the operational uptime in the UK for the first quarter?

And then looking at the U.S. because the U.S. has got significant declines as well when you look at that as well.

I find it just hard to comprehend given the fact that you have had obviously just reported a rapid ramp-up in Ormen Lange, and you have had start-up and ramp-up on a number of other fields in the Gulf of Mexico.

I was just wondering in that how much decline in the Gulf of Mexico is going to offset Thunder Horse if that comes on towards the end of the year?

Then just as a second question on Refining & Marketing, which is given your global reach in Refining & Marketing, are you seeing anything from the Marketing segment at the moment that would give you indications that consumers are holding back in terms of their usual buying activity of your products?

While Fergus takes a look at some specific numbers, let me talk again about the bigger picture, the longer-term picture with respect to our production from our Exploration & Production segment.

We indicated earlier this year, confirmed that we were on track with the strategic indicator that we had provided a year earlier.

And that if we look out over the course of the period to 2008, that we saw production growing at a rate of about 5% per annum on average over that period of time, and that that rate would be similar in TNK-BP as it was in the rest of BP.

Within the existing profit centers of BP and you have spoken to the North Sea and North America, within those we would continue to see a 5% underlying decline that would be offset by about 2% from operating efficiencies.

We have not seen some of them coming through in the first quarter, but offset by operating efficiencies and the start-up of production from new fields like Clair, which we mentioned had occurred in the first quarter.

So we believe that there is nothing that is happening out there that in anyway takes away from this indication that based on a $20 world, because we need to standardize for production sharing contracts, but in a standardized world that we will see the 5% growth on average out to 2008 and that we will see in the existing profit centers the decline mitigated to about 3% by the investments we have made and the actions we're taking and that a 90-day period in no way puts that longer-term projection in jeopardy.

Fergus?

And just to follow-up on the detailed numbers just to be absolutely clear, in terms of comparing the first quarter of '05 to the first quarter of '04, the reported barrel of oil equivalent production for the U.S.

I think shows a 4% decline.

About a third of that was related to divestments.

And just backing out Byron's point, when you turn to comparing the first quarter of '05 with the fourth quarter of '05, of course, as you know production was up actually by 3%, which is really making Byron's point about if you like a corner being turned there in terms of the relationship between new start-ups in the Gulf of Mexico relative to the onshore.

On the ops efficiency number, the percentage uptime I think you are looking for here for the UK to back up the comments I made about sheer water and other North Sea ops efficiency issues, then how about a hand trying to get you about this later this afternoon.

And finally, in terms of are we seeing anything in marketing saying demand is being adversely affected by high prices, too soon to say.

Clearly there has been a big compression in marketing margins as a result of the strength of refinery gate prices and the strength of crude oil.

Disentangling that from underlying demand trend is very tough at the moment, but if we see anything there, we will clearly let you know.

And if you look at it from the perspective of a European consumer at least with respect to motor transport fuels, the underlying cost of the product is still a very very small component of the overall cost that is paid in the United Kingdom for example.

Still approximately 75% of the price that you pay as you fuel your vehicle is tax that goes into the government coffers.

So we are not seeing it.

We are not seeing it here.

We are not seeing it in North America, and I agree with Fergus, it is perhaps too early or perhaps it requires a much higher movement in prices or a much longer sustained period to actually get consumers to materially change their buying habits.

I have got one question from the Web from Gene Gillespie at Howard Weil, and Gene's question is, can you provide a start-up date, 2005 exit rate and a peak production rate for the Thunder Horse project?

We are on track for a 4Q start-up.

This is designed to process about 250,000 barrels a day of oil and about 200,000 -- or 200 million cubic feet a day of gas.

Our working interest just to remind everyone is 75%.

The figures I'm quoting you are where it gets to, and we really cannot provide you specific exit rates project by project.

Coming back to the telephone, we've got a question from Peter Hutton (ph).

Just two very quick questions.

First one, you normally state that shares have been repurchased at cancellation.

This time in the notes you say that the Company has repurchased 193 million shares of which 77 million were canceled, the remainder held in treasury.

Is this a change in treatment?

Can treasury shares be held and transferred to, for example, the TNK as part of the next tranche?

And the second question is, you mentioned that there were some savings in the Olefins & Derivatives as a result of the restructuring last quarter.

Can you quantify how much those were?

And also you took another 23 million asset impairment this quarter.

But wasn't the 1.1 billion that you took last quarter enough?

Can we expect more, or is that it for now?

Thank you, Peter.

I will start with treasury shares.

This is something that as you have noted we have just begun doing in the course of the first quarter.

Treasury shares are much more restricted in the United Kingdom than they are in the U.S. and Europe.

But we cannot use them as acquisition currency, so we cannot use them as part of the payment to TNK-BP.

It has no stamp duty benefits.

Its limits -- our limitations pretty much confine it to use for various employee share option schemes.

Now we clearly don't need as many shares as we are putting in to fulfill the obligations on the employee share schemes.

So we have seen no particular downside associated with putting the shares in treasury as opposed to canceling them.

And consistent with what a number of other large corporates who are involved in buyback programs in the UK are doing, we have decided to put our buyback shares into treasury.

It does not impact any of the metrics that you see.

It is there at the current time only aimed at the ability to meet obligations to employees under various share schemes.

And coming to your question about the contribution of savings, cost savings to the $270 million or so improvement in the underlying Olefins & Derivatives performance relative to the fourth quarter, Peter, I cannot give you a precise calibration of the contribution there.

But as I have mentioned earlier, there is a fairly long list of contributors to that improved performance, including cost but also including margins, the fourth-quarter contribution from Solvay and the French refining.

So it is a small part of that.

You will be getting a lot more detail on the whole issue of cost structure at Innovene when we in due course publish the listing documents for the IPO.

We are very pleased with what we have managed to accomplish by segmenting out Innovene from the rest of BP.

It is legally separated now.

It still operates as part of the group, but is operating independently, perhaps is the right way to describe it, within the group to itself.

The focus of Ralph Alexander, the Chief Executive and his team, have been to manage the cost structure as a way an independent petrochemicals company would do and also with an eye towards the revenue side of things.

So I believe that the team has made good progress on a number of counts in the first quarter.

This bodes very well for an IPO because the value that is being unlocked here by the actions that are being taken, as well as the assets we have put in going back to Lavera and Grangemouth, all of this will be realized in the value that is achieved when we place these shares in the public market, as, indeed, we remain intending to do in the fourth quarter.

With respect to your question about $23 million more, that relates to the completion of the Solvay acquisition.

That was impaired, as you know, in the fourth quarter.

This was a final adjustment on that transaction, and since it had already been impaired, the additional costs clearly needed to be impaired as well.

Would we expect to see anything going forward?

I certainly don't expect so at this time, but impairments are consistent with accounting standards reviewed on a regular basis.

And if there is the inability to support the accounted result, then steps are taken, and we as a company have very very tightly controlled processes for doing that.

Gordon Gray at J.P. Morgan.

Just a couple of quick ones.

I know you can't give us guidance on specific project detail at the end of the year.

But can you give us an indication of a sort of overall exit number on volumes, say, compared to last year to give us confidence on the timing and the impact of the late year big projects in E&P?

And secondly, how important is mix effect in improving E&P (inaudible)?

Are you still comfortable about the accretive nature of the new barrels versus the old?

Well, the answer, Gordon, is the only indicator that we have given you for this year is the one we stand by is 4.1 to 4.2 million barrels a day of production on average for the year based on our traditional $20 a barrel planning assumption.

Clearly when you see the schedule of projects that we have shown you several times and showed you again in February, you will appreciate that there is a large number of these larger projects of which Thunder Horse is prominent coming onstream towards the end of this year.

So a reasonable person might expect to see an impact of that as the year closes and as we move into the early part of 2006.

There are actually six project start-ups in the fourth quarter of this year.

So that gives you a flavor I hope.

In terms of the margins associated with it again, we have talked about this before.

You know that our objective is to bring onstream new projects with cash returns at least equivalent to the existing, and we stand by that.

I think you have seen some of the impact in this quarter of the mix effect associated with particularly Gulf of Mexico production in this kind of pricing environment.

Michael Hume (ph) from MFS.

Good afternoon, gentlemen.

I just wanted to ask a question further to Neil's question really regarding UK volumes.

Obviously they were down quite substantially or rather surprisingly given that UK margins, upstream margins, were pretty strong.

In fact, stronger sequentially and year on year.

And on the flip side, while you have got slightly lower decline rates in the U.S., you have got pretty weak margin trends there.

I wonder if you would like to comment on those?

I will start off with the U.S., Michael.

I mean clearly the point there is that -- one of the key points -- is that U.S. gas prices were down sequentially against the fourth quarter, whereas oil realizations were up.

So there is a significant impact given that we are North America's largest gas producer from the decline in U.S. gas realizations, which I think is the bulk of the effect that you are talking about in terms of operating profit per barrel and the U.S. result.

As regards the UK, there is a very substantial improvement in profit there year on year, just over $10 a barrel of operating profit, 64%.

So I think perhaps we should take this one off-line in terms of getting to the bottom of your question.

Thank you very much, everybody.

Thank you.

It is always a pleasure to have the opportunity to respond to the questions of investors and the analyst community who follows BP.

It is particularly pleasing to be able to do it in a quarter where the results of the group have been as strong as they have been, both with respect to the reported results and the underlying cash flow.