英國石油 (BP) 2004 Q2 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 the Head of Investor Relations, Mr. Fergus MacLeod.

Please go ahead sir.

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

I would like to welcome you to BP Second Quarter 2004 Conference call.

I'm Fergus MacLeod, BP's Head of Investor Relations.

Joining me today are John Browne, BP's Group Chief Executive;

Byron Grote, our Chief Financial Officer; and Tony Hayward, Chief Executive of our Exploration and Production segment.

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

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

If you are listening 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 already have received the slides.

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 terms will, expect, and similar phrases.

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

Now, over to John.

Thank you Fergus.

Again, a very good afternoon to those listening in Europe and a very good morning to those in North America.

Thank you very much for taking the time to join us today.

In a few moments, Byron will as usual review the detail behind our results.

We will then be happy to take your questions.

Before we do that, I would like to take a few moments to step back and set these results in context.

It's almost exactly six years since we announced our merger with Amoco and just over five years since we announced the transaction with Arco.

Since then, we've built a company with a unique combination of assets and the potential to deliver outstanding returns to shareholders.

That company produces around 4m barrels of oil equivalents a day and has proved reserves of 10.3b barrels of oil and 46.5 trillion cubic feet of natural gas.

We're the industry leader on several measures, including longer run reserves replacement and F&D costs.

The figures for the first half demonstrate that we have the ability to deliver shareholder value from the new base we've created and that we have the potential to grow and to improve in both in terms of volumes and returns.

The momentum is very positive.

The results you see today are strong but they are just the beginning.

The real potential of the new Company has yet to come.

Turning now to the overall trading environment, let me make three points.

First, demand for energy is rising, driven by strong economic growth, particularly in China but also in Russia, India, and Brazil.

Demand maybe slowing a little but we still expect oil consumption rising by over 2m barrels per day this year.

Second, there is a climate of uncertainty, which has pushed up oil prices.

At around $40 a barrel, current oil prices clearly include a premium reflecting concerns over security of supplies.

OPEC has increased production but today's capacity utilization is high and OPEC's control is still in place.

Over the next few years, new capacity is expected to come on stream in several places, but mostly from West Africa, the US, Russia, and the Caspian.

Oil prices remain impossible to predict and at the project level we continue to plan prudently.

However, it does now seem likely that oil prices will be very significantly high above their long run average of $20 a barrel for some time to come.

Third, despite strong crude prices, refining margins so far in '04 have been at their strongest levels since 1986, principally because of the low stock position and strong demand.

Let me now pick four highlights of our performance in the first half of '04.

A record result of $8.6b, up 20% over last year's first half; a record adjusted operating cash flow of $12.4b, up 15% from last year's first half; a record production rate of 3.993m barrels of oil equivalent a day, up some 14% above the first half of last year, and record quarterly dividends of $0.071 per share, 9% above the level of 2Q03.

Our focus continues to be the delivery of our strategy through investments at the appropriate rate for long-term growth, and through operations to generate free cash flow.

To generate that free cash flow, we focus on capital expenditure, divestments, returns, and gearing.

As this slide shows, capital expenditure for the year is expected to be slightly higher than that forecast in March, as a result of non-dollar expenditures translated into dollars at a weaker dollar rate, higher raw material prices, and E&P supplier pricing power in a tighter market.

Divestments are running at an expected level, above the range of $3b to $4b given in March.

Operating capital employed was risen by around 14%, but because of our distinctive leverage to higher oil and gas prices and US refining margins, and because of good operational performance, pre-tax cash returns have stayed at 34%, a level similar to last year's first half.

In spite of significant share buybacks, gearing was at 23%, below the bottom of our target range of 25% to 35%, and we expect to get back to the lower half of that range by year-end.

Everything we do is undertaken within a clear long-term financial framework.

After paying taxes, almost half of our remaining cash flow was reinvested, and the rest was returned to shareholders.

So far in '04, we've returned over $6b to our shareholders through dividends and buybacks.

In the UK, that represents around 15% of the annualized distributions made to shareholders by all of the Companies in the FTO share index.

In other words, almost 1 pound in every 6 pounds received by pension funds and similar institutions comes from BP.

US investors are of course also participating, around one-third of the $6b has benefited US shareholders.

We are implementing our strategy as we said we would.

Our major projects in our five new profit centers are on track, and in Russia our TNK- BP joint venture is performing well, and fully in line with the objectives we've set.

Results in Refining and Marketing are close to a record level, and in our petrochemical segment, we are making good progress in preparing our Olefins and Derivatives business, full divestment mostly likely for IPO.

The share buyback program and the consequent lower number of shares in issue has allowed us to accelerate the growth of our per share dividend, which is up by 9% or $0.006 a share from the 2Q '03 level.

Now this $0.006 per share could be looked at as $0.005 from the established pattern of quarterly increases plus $0.001 from the reduced number of shares.

If the environment allows us to continue to repurchase shares, and in particular fuel prices remained above $20 a barrel, we will continue to be able to increase the per share dividend at a rate, which not only reflects the long-term growth of the group, but also reflects the allocation of the group's dividend payments across the reduced number of shares.

Let me now turn to the business segments, starting with Exploration and Production.

We expect production in '04 to be above 4m barrels of oil equivalent a day, an increase of more than 10% from '03's level, in spite of some operational outages at Moss in the Gulf of Mexico, and adoption at LNG plant, amounting in total to some 35,000 barrels a day during the last quarter.

We said at the time of the 1Q results that our '04 capital expenditure measured in US dollars might be affected by the continued weakness of the dollar, compounded by some price increases in raw materials and supply producing power.

We now expect '04 E&P capital expenditure to approach $9.5b compared to the $9b level estimated in March.

The results of this increased E&P expenditure is that overall growth CapEx in '04 is expected to be around $14b.

Turning to our major E&P projects, this slide shows that all the project schedule to start up this year are on track.

You should note that not only these projects were in the five new profit centers; the Clair field where the jacket and deck have now been installed is an example of a new project in an existing profit center.

Production from the existing profit centers is declining, but Clair and other projects in the North Sea, Argentina, and elsewhere are hoping to keep that production decline in the range of 3% to 4% a year.

Turning to Russia, TNK-BP is performing well.

Production this year is expected to be up around 12% or 150,000 barrels a day compared with '03.

This is being achieved through the application of modern practices in oil field management such as waterflood optimization increasing the efficiency of downhole electric submersible pumps and applying new hydraulic tracking techniques, all to increase recovery factors and production.

TNK-BP is increasing its capital expenditure as it accelerates new developments, but this is entirely self-funded.

This year, we expect TNK-BP to pay a gross dividend of well above $2b, while still keeping gearing at the low-end of its target range of 25% to 35%.

Turning now to refining and marketing, we have seen refining margins at the highest level since 1986.

Continued good refining availability has allowed us to capture much of this strong environment in our results, despite some problems at our Texas City Refinery.

In marketing, lubricant sales have been especially strong and the numbers of major markets in which we're marketing are differentiated fuels under the ultimate brand, continues to grow.

In Gas and Power, strong volume growth continues even in North America, where we are already the number one producer and wholesale marketer.

Another step was taken towards the long shift of Tangguh LNG project in Indonesia, while in Egypt; we are establishing the base for another major LNG business.

Finally, in petrochemicals, we are making good progress and preparing our Olefins and Derivatives business for sale, potentially by way of an IPO in the second half of 2005.

The Aromatics and Acetyls business, which we are retaining, continues to expand its capacity for the Chinese market.

Before I conclude, I want to mention the filing of our 2003 Form 20-F, which happens since we last spoke to you.

In this filing, we applied SEC rules to the reserves reported in our Annual Report resulting in a positive, but quite immaterial difference of 23m barrels.

This difference arises from the SEC's requirement to use year-end pricing, our application of the SEC's interpretive guidelines and the reporting of fuel gas with improved reserves.

We understand your concerns about reserves and we support International moves to improve the comparability of individual Company's estimates.

We remain confident in our process and methodology for estimating reserves.

Now, you will recall from our March presentation that we have only three delivery targets.

First, to reinvest the rate appropriate for long-term growth.

This is what we are doing with an expected level of organic capital expenditure of around $14b this year.

We continue to expect for the organic capital expenditure in '05 and '06 will be around a $1b below this level.

Second, to increase the dividend of the rate, which is sustainable for the long-term.

As I have explained, the reduction in the number of shares outstanding due to the buyback program may allow a more rapid progression in the per share dividend that would otherwise have been possible.

And third, to distribute to shareholders 100% of all free cash flows and excessive investments and dividend needs, all other things being appropriate and generally when the price of oil is above $20 a barrel.

In the first half of April, we bought back 3.25b of shares.

Some of you may remember the slide we showed in March indicating the potential distribution to shareholders over the '04,'06 period under three different oil price scenarios, $20, $25, and $30 a barrel.

In fact, in the first half of '04 the average Brent oil price has been $33.70 a barrel above the highest of the three scenarios.

The effect of this is shown on the slide.

Over the first six months of '04, our distributions to share holders have been $6.25b more than twice the level of both the first half of '01 and '02 and around 30% above those of the first half of last year.

This is a very satisfactory outcome, but we do not intend to stop here.

The best as they say is yet to come.

Now let me hand over to Byron, who will give you more of the detail of our results.

Byron.

Thank you John.

I will now cover our results for the quarter and year today.

As shown on the left, trading conditions for upstream business remain strong in the second quarter.

Our oil realizations average more than $34 a barrel, one-third higher than 2Q03.

Our gas realizations average nearly $3.70 per thousand cubic feet, up 9%.

Compared with 2003, our overall hydrocarbon realizations were up 23% in 2Q and up 10% for the half year.

As shown on the right, the industry indicator refining margin approached $8 per barrel in 2Q supported by strong global product demand and a tight US gasoline market.

The margin gains for our own refining portfolio was substantial and less dramatic than suggested by the indicator margin.

Although not shown, marketing margins were low early in the quarter and then recovered in June.

Our average retail field's margin in 2Q was higher than in 1Q but lower than in the second quarter of last year.

Petrochemicals margins continue to improve with the global economy but remain under pressure due to high feedstock and energy prices.

Continued pressure from dollar-based imports limited the margin improvement in Europe.

Overall, the business environment was very strong and contributed to the record first-half results we reported this morning.

Starting with the second quarter data at the top of the slide, our pro forma result of $3.9b was up 23% compared with the second quarter of last year.

A replacement cost profit of $3.4b, which includes acquisition impacts, was up 35%.

Our historic cost profit of $3.9b, which includes both acquisition impacts and realized inventory gains and losses was more than twice last year's level.

Our post-tax adjusted operating cash flow of $5.3b was down slightly compared with 2Q03.

Last year, working capital declined as prices fell.

In contrast this year, working capital increased as prices rose.

This is normal.

Excluding working capital movements, our 2Q operating cash flow improved 75% year-on-year.

Our first-half results were up across the board, each of the measures shown is a record for the half-year again reflecting the strong trading conditions I noted earlier.

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

These fall into two categories.

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

You will recall than in 1Q these totaled the gain of $1.3b mainly profits on the sale over a successful investments in Petro China and Sinopec.

This quarter, post-tax exceptional losses were just under $100m mainly related to disposals in ENP.

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

We include the accounting adjustment for unrealized profit and stock or UPIS in this category as they can have a material impact on quarterly results.

In the first half, these items totaled a loss of nearly $300m post-tax.

Around third of this was the UPIS charge directly related to rising oil prices.

Our stock exchange announcement provides further details of these items.

Before leading the slide, I would like to refer back to the third quarter of last year.

As you may recall, we reported pre-tax environmental remediation charges totaling $500m in that quarter, about half related to a shift to a consistent group-wide methodology and that is shown as a non-operating item.

Our 2004 environmental review is now in progress.

Current indications, although we may see new provisions of a similar overall total amount.

We'll provide further information on the results of this review in our 3Q trading update in early October.

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

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

These items make earnings enhance variety more volatile.

For example, the decline of BP's headline return in 2Q messed the actual improvement, because of the absence of the 1Q gain from our Chinese share sales.

We expect introduction of international financial reporting standards next year to make earnings and variety more volatile.

For these reasons, we find cash returns a better indicator of business performance.

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

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

By removing the volatility related to tax phasing and price driven working capital changes, we believe this measure provides a clear view of cash generation.

Our 36% cash return in 2Q, represents higher cash generation under growing capital base.

The data shown are based on actual prices and margins.

The peak in 1Q03 and the increase in the first half of 2004 are driven by strong trading conditions.

After effecting our changes in the business environment, we believe that the underlying trend of our cash returns remains one of improvement, and we expect the underlying return to grow by around 2% points by 2006, as capital in our major projects and our service.

This chart shows the main elements driving the $1.4b improvement in our first half result from $7.2b in 2003 to $8.6b in 2004.

The main sources of improvement shown in yellow are greater gains from exceptional and non-operating items, the stronger business environment and the cumulative effect of acquisitions and divestitures.

I've already discussed our exceptional on non-operating items, so let me cover the remaining too.

The stronger business environment added around $1b to our first half result.

This includes a $1.25b improvement in prices and margins as described earlier, lesser $250m adverse foreign exchange impact.

In total, our portfolio upgrading activity over the past year added around $300m to our first half result.

The TNK-BP acquisition added some $550m, which more than offset the impact of disposals in EMP and the customer facing segments.

Depreciation charges excluding foreign exchange effects were up a $150m between years on a post-tax basis.

The increase is mainly in expiration production and reflects the change in portfolio composition and a startup of new projects over the past year.

We also saw a $150m impact from an increase in the goods effective tax rate from 34% in the first half of last year to above 35% in the first half of this year.

Higher pre-tax earnings, larger due to stronger price in margin environment, drove this rise in the effective tax rate.

As I explained in our March strategy presentation, these higher earnings are taxed at a marginal rate of around 40%, which in turn increased the group average tax rate.

All other factors basically netted out between periods, as underlying improvements in our operations offset inflationary pressures.

The figures just discussed include a strong contribution from TNK-BP.

As shown here, our share of TNK-BP net income was $374m in 2Q, compared with $219m in 1Q.

After subtracting the accretion of discount on the shares, we will issue to Alfa, Access-Renova.

TNK-BP contributed $348m to our 2Q net income, up from a $193m in 1Q.

The 2Q result includes a full quarter contribution from Slavneft for the first time, which amounted to $40m in 2Q, compared with $31m for 76 days of ownership in 1Q.

It also includes a $7m charge related to finalization of our results in prior periods.

The 2Q improvement is dominated by increased volumes, price effects, and favorable tax lags.

Production rose by more than 7% between 1Q and 2Q, partly reflecting the inclusion of a full quarter of Slavneft volumes.

Crude oil volumes were up 6% and gas volumes were up 18%.

The Euros' price into Northwest Europe rose nearly $3.50 per barrel in the quarter, and Russian domestic prices increased by around $2.50 per barrel.

Russian export duties are linked to the Euros price but lagged by around 3 months, thus benefiting our TNK-BP earnings in the second quarter.

TNK-BP did not pay a dividend in 2Q.

However, in the first half of July, we received $450m with respect to 4Q'03 and a portion of the first quarter.

We will show $23m of this as an offset to the Slavneft acquisition price and the rest is operating cash flow in the third quarter.

Turning from cash flow back to earnings, I'd like to mention two material items that will influence TNK-BP's future results.

First, the higher Euros' price in 2Q will drive higher export duties in the third quarter.

Assuming production growth remains on track including product exports remain around 70% of production, we estimate that the lagged higher export duties at unchanged fiscal terms will reduce TNK-BP's 3Q earnings by around $55m net to BP, relative to 2Q.

In addition, future earnings will reflect the recent changes to the Russian fiscal regime, which I mentioned in our 1Q webcast.

Russia is introducing progressively higher rates of production taxes and export duties when the Euros' price exceeds $20 per barrel.

The higher export duties become effective in August and the higher production taxes start in 2005.

In 3Q, we expect the new export duties to reduce our share of TNK-BP earnings by around $65m.

Adding these two items, our share of TNK-BP earnings in 3Q will be around $120m lower than the 2Q result shown on this slide, other factors being equal.

Groupwide cash inflows remain robust in the fist half.

Operating cash flow of $12.5b before pension funding was a record.

The China share sales and other disposals added $3.6b after tax, bringing total sources to more than $16b.

Well, we invested a round $6.4b of this cash directly back into the business.

In addition, we invested $1.35b to incorporate the Slavneft interest into TNK-BP.

Dividends totaled $3b and we bought back $3.25b of shares.

In aggregate, total cash sources have exceeded uses by $2b despite year-on-year increases in organic CapEx, acquisitions and shareholder distributions.

This resulted in a lower net debt.

As shown here, we ended 2Q with 23% gearing -- down from 26% at year-end 2003, and remaining below our target band of 25% to 35%.

We aim to restore gearing to the bottom half of the band by further distributions to shareholders.

Our policy is as we stated in March, as long as oil prices remain above $20 per barrel, we intend to return 100% of additional cash flow to investors.

Consistent with this, we have already purchased another $500m of shares in 3Q under our close period buyback program.

As you may recall, we have agreed with Alfa and Access-Renova to suspend buybacks during the 30 days that are used to determine each $1.25b deferred share payment for TNK-BP.

The 2004 suspension is from August 21 through September 19.

Other factors being appropriate, we expect to continue buybacks up to the suspension period and to resume buybacks thereafter.

This chart compares our shareholder distributions in the first half of 2004 with previous full-year totals.

It's another way to illustrate the points that John made earlier.

We distributed more than $6b in the first half of 2004.

This exceeds the full-year totals in 2001 and 2002, and is 80% of our full-year 2003 distributions.

It does not yet reflect the buybacks we've already made in the third quarter nor the 9% year-on-year dividend for share increase we announced this morning.

The strong trading conditions I noted at the start of my remarks have allowed us both to return cash to the investors directly, via share buybacks and to increase the per share dividend to our continuing shareholders.

That concludes our prepared remarks.

We'll now are pleased to take your questions over the phone or the Internet.

If audio participants would like to ask a question, they may do so by pressing star one.

To cancel your question, press star two.

Right.

Thank you very much ladies and gentlemen.

I would like to take a question from Doug Terreson of Morgan Stanley please.

Doug?

Now we will come back to Doug.

I will take one from Tim Whittaker, Lehman Brothers, please.

Yes.

Good afternoon gentlemen.

You spent a lot of time talking about distribution to shareholders and previously you gave the slide showing anything above the 20 of those or above, you would distribute.

Could you comment how down street margins being above mid-cycle affects your rate of share repurchase, and also can you say whether you consider changing the mid-cycle assumption you used to drive your dividend, perhaps?

Thank you, Tim.

I think I would answer this very briefly. $20 a barrel is the safest way of looking at it or in terms of a big picture, what we actually look at of course is the total cash flow, the total free cash flow, and keeping our gearing in the band of $25 to $35, we did say we keep in the bottom half of that band.

So, all of that sums up to say if the down stream does well, of course that contributes to the level of stock buybacks with no intention of changing our planning assumptions.

We didn't have mid-cycle assumptions any more, that was probably a -- I think of the past, but we don't intend to change that, that's we don't need to.

It's a way of thinking about balancing the cash flows in the Company to make sure we are investing the right amount of money for long-term growth.

Thank you.

Thank you, Tim.

Let me try again Doug Terreson in the US.

Doug?

Good afternoon, Lord Browne and Company, can you hear me?

Yes.

Okay.

On your position in Russia, I had a couple of questions.

First your presentations to get the BP-TNK, which self-fund $1.3b in CapEx this year, which seems pretty likely, given your strong first half results.

But on this point I wanted to see if this figure represented a change in your expectations for '04?

And also what is CapEx profile that you highlighted at the March meeting has changed as well given the changes in Russia, and if so by how much and why?

And my second question what has to do with Kovytka.

The Russian government appear to be interested in accelerating the development of that project, and so I was wondering if you could provide an update on that project as well and whether or not there have been any changes to your thinking as it relates to the development plan.

Tony to answer these questions.

Tony.

Hi Doug.

The $1.3b is in line with what we set for TNK-BP for 2004 and we'll continue -- sort of review that as we see the scale of the opportunity, say, going forward.

In terms of Kovytka, I think the key thing is establishing the right relationship with Gasstrom and we are engaged in a very constructive dialogue with them around how to move that project forward.

Yes.

And Doug, there is nothing which is influencing us in terms of what I think many people have asked us about which is the

.

Everything seems to going in order as far as TNK-BP is concerned and we have good assurances that we are doing the right thing in the right way.

So, can I now turn please to John Rigby of Commerzbank, John.

Good afternoon.

Good afternoon.

I've got two questions for this and related to the same thing.

First, as you talked about how your best estimate outlook is that oil prices will remain above 20 bucks for sometime.

I wondered if there is scope for a little bit more sort of dynamic management to cash flow in it, and medium term investments could be tested against the

of share buybacks and whether you can generate more shareholder value by making some of tactical investments around the edge?

And the second is sort of related to that, is that again, related to that is that you could also test whether divestments also work in that relationship and tied to that and just how is it that, that you are able to generate losses on disposal in the upstream, $35, $36, $37 a barrel, when presumably they are being tested at 20 bucks, your planning assumption at some stage in the past few months?

Fine, I'll ask Byron to talk about the disposals, let me just talk about the way we plan investments?

John as you

I think, maybe Tony can add more.

There are very few tactical investments

last several years and a very few tactical investments that if we are not investing as it were in an artificially constrained $20 environment that have some how a better return, a $20 if we do them with a $25 environment.

In other words that's sort of a clumsy say of saying, it is to us very important to keep the quality of this portfolio up as well as the quantity of the portfolio.

So that's really what we are be doing, it's quality, it's choices that keep us

on the returns access as well as the growth access and this is very, very important to us.

We see middle point instead of degrading the quality of the portfolio.

By further investment we must refer disciplined approach to this, which is very secure, so that we can therefore return the free cash flow that we don't need for long-term growth, and the company will grow but so to returns improve rather than spend it wildly.

Now, let me say, divestments are done on the basis of where the market actually is, not on $20 a barrel.

But Byron the losses on disposals?

Well, you're right John, that we do regularly test all of our assets as to whether or not they need the criteria for and various impairment criteria.

Above what happens as you would expect in field periodically is new information comes in and that new information related to the long-term recovery from the field or that new information related to the cost structures around it or lead to a reassessment and sometimes this is crystallized through an impairment charge and so, or sometimes it's actually realized through a loss on sale if we decide to divest in it.

But, the dynamics that you are describing about testing the carrying value of our assets is something that is fundamental to our practice.

Okay, thanks.

Great, thanks John.

And Mark Flannery, CSFB, good morning.

And can I just clarify one point about CapEx, when you mentioned $500m increase for this year, some of it related to inflation, some to the dollar and assuming the dollar stays where it is, should we roll that extra $500m forward for the next couple of years and in other words do you see this is a permanent step up or is there something more related to this year in particular?

Mark it is not all Forex, but quite a bit of it is and if exchange rates stay exactly where they are today, then we'll roll that forward, that amount.

And the remaining piece, which is oil, serviced inflation;

I guess we take a view on inflation on oil service charges for that?

I'm sorry, I hate the word inflation, I think bottom line is its supplies using a bit of extra power that got in a tightening market and is also raw material process, but these are minor impacts, the raw material prices, not less than that and it's primarily to do with things like steel.

If you remember Mark, when we made our presentation in March, we attempted to be very clear that we would put these forecasts together on the basis of what we felt were reasonable long-term exchange rate assumptions.

For example $1.60 to the pound, and $1.10 to the Euro.

To the extents that the 20% or so of our capital spending which is not dollar denominated has to be acquired at less favorable exchange rates, then that would really write through to increased capital spending.

Right, thank you very much.

It's Mark Iannotti of Merrill Lynch.

Good afternoon.

Hi, gentlemen and can I have the same question as Mark -- so can I just absolutely clarify, you said in your initial statement or in your initials comments showed CapEx would be a $1b below this year's level of $14b in '05 and '06.

That's a jump from the $12b to $12.5b guidance that was given in March?

So, can we

of extra CapEx that we are now looking at for '05 and '06?

Then the difference in exchange rate, are you actually changing your exchange rate forecast or is there something else we should thinking about, are you seeing cost overruns or any specific fields we need to be looking at?

No.

We are not seeing anything unusual here.

This is primarily the same effect running forward and also to the other marks -- question mark, Flannery's question.

Okay.

Thank you, and Neil McNoron.

Hi, just two questions.

One, first of all looking at the North Sea.

Can we get an update on the production uptime that you been experiencing in the North Sea in the second quarter, and an idea of -- when you look at the forwards gas contracts in UK, especially for the first quarter of '05, it looks very strong in terms of pricing.

What percentage of your gas contracts out of the UK would actually see an uplift and therefore reflect the spot prices?

And, maybe lastly could you just give us a few comments on the status in Georgia with the BTC pipeline?

Great, thank you.

Tony, North Sea?

In terms of operations, we've had a good first half.

Of course, we are now beginning to enter the turnaround season.

So, if you look at the first half, our uptime is about 8.5%, I think, through the first half.

That included plant shutdowns in the second quarter, they will continue through the third quarter.

Looking at some of the UK gas contracts, about 60% of it is subject to spot prices.

Great, Georgia?

In Georgia, as I am sure you've seen in the press, we have temporarily suspended operations in Borjomi, depending a review with the government of the security measures around the pipeline.

I think the important thing to say is that in meetings that we had with the President of Georgia, he has given us his personal assurance that nothing will happen to prevent the project being completed and we continue to make very good progress.

So, overall the project is 75% complete.

In Azerbaijan, it is more than 80% complete, now it's 85% complete.

In Georgia, it's close to 80% complete, and in Turkey it's 75% complete.

So, things are going well, we are having a short interim while we review the final security arrangements around the pipeline through Borjomi.

And, Neil if can just add.

I met the President of Georgia and he was very clear that his assurance was that it would it completed on time.

I believe he gave the same assurance to a whole variety of people in governments around the world.

So, that's where it is at the moment.

Okay, thank you so much.

Thank you, Fred Leuffer of Bear, Stearns.

Good afternoon.

What was your Alaskan production in the quarter?

And can you update us on your expectations for the rest of this year, and '05?

Fred, in Alaska or everywhere?

Alaska.

Thank you.

Tony?

Alaska was -- I am just looking to confirm, its around 315,000 barrels a day in the quarter, and we would expect it remain -- 310 is what I was just been told.

We would expect it to remain at around that level.

We see Alaska being broadly flat in terms of production as very gradual decline of conventional oil is replaced by an increasing wedge of viscose oil from the new viscose developments we are undertaking in Alaska.

Thank you.

Thanks Fred.

J.J.

Traynor, Deutsche Bank, good afternoon.

Good afternoon, couple of questions please.

Firstly on reserves, you've been through the process of restating your oil and gas reserves for the SEC rules.

Probably there are still some different interpretation of those rules out there, example Oman

was supposed --do you think that the SEC should change or update its rules, and which areas if any do you think they should look at, and secondly a very unrelated question, returns to shareholders, the buyback is accelerated quite substantially with the oil price, but hasn't had a dramatic impact on the share price, do you think you should consider a special dividend?

Thank you, let me just handle these, and maybe I handle with Byron as well.

First I think JJ, the way I look at this in reserves is there really are two different languages and there is an interpretation between both.

There is a language for us, which we use in our annual report UK stock, and there is a language, which are required to use for our Form 20- F in the United States, which is the SEC.

Turns out of that, they are pretty close to one another, but there are some differences.

I hope one day that we will get conformance with these definitions because I think that's good in everything and your concept of one side either of these systems, SEC is been at this for 30 years on filing down the rules that they use, but some of them may be a little out of touch with what we are doing as in industry as a whole today, but our equity, I think I am very realistic about the difficulty of getting international standards, after all look out how long it is taking us even to embark on international accounting standards, and they won't be international, I think for some time.

Returns to shareholders, I mean we are returning the cash via to shareholders by buying back stock, we continuously ask people in the market where their preferences lie and overwhelmingly it's for share buybacks, and say that's what we can continue to do.

Remarks to that.

JJ you asked a question and using the word restate, we haven't restated our reserves.

As John indicated, we just translated our reserves into the SEC language, and as far as the idea of a special dividend, there really has been nobody to the best of our knowledge who's ever dealt with an ongoing flow of cash beyond the quarter-to-quarter needs through a special dividend mechanism, and as we have asked investors as John indicated, they continue to believe that the best way to deal with this is through the simple mechanism of share buyback.

All right, okay, thank you very much.

Thanks JJ, and John Rigby says the group, good afternoon.

Question on Russia please, and just looking year 2003 TNK-BP US GAAP accounts, the transportation costs were up sharply about 80%, and I wondered at what oil price the export by road and rails start to become marginal?

Do you have feel for that?

Let me try and give you some sense for that John.

The first thing is as you, I think everyone appreciates, there are multiple routes to market and what we are seeking to do is to optimize on a weekly basis the route by which the marginal barrel goes to market.

I think historically the marginal barrel has been well north of $25 a barrel, this will change probably as the new export revenue taxes are introduced, which effectively caps the realized price at around $25 in fact, so as we go into the next year, we will get some different dynamics occurring in the export system coming out of Russia consequence on this new tax.

Historically, $25 has been the sort of number, as we go forward I think we like to certainly see how that develops.

And do I assume that the pressure would be upward on that price?

Yes.

Okay, thanks.

And may be a preference on the margin to as you sell this domestically, but I think these will favor to go dynamics into we actually see what's happening but we'll see it is pretty soon, I mean winter arrives relatively early.

Good.

Thank you very much John.

Robert Kessler of Simmons & Company, good morning.

Good morning.

Some additional follow-up on your production figures if I may.

First, if you could provide the year-over-year adjustments for assets, divestitures, and then secondly, the split between Mars and Trinidad downtime, you mentioned a 35,000 barrels a day and assuming somewhat close to 20,000 barrels a day for Mars alone would be resumed but, wanted to get your thoughts on that.

Great.

I'll ask Tony to answer the second part first, while we just to make sure we get the numbers right for the first.

On the second one, it's 20,000 barrels a day in Trinidad and 15,000 in Mars.

In terms of what -- looking at the year-on-year

excluding TNK BP, I'm going to give you percentages rather than specifics, I don't have the specific numbers in front of me but, excluding TNK BP, the portfolio of half-year to half-year is down 7%.

If you corrected the volume for the divestments, it is down 3%.

Great.

Thank you.

The divestments account for 4%.

Robert, it's Fergus MacLeod here.

I would be very happy to talk you through the detail offline, if you'd like to do that after the call is over.

I would appreciate that.

Thank you.

The divestment amount is 151,000 barrels of oil equivalent a day, 1H to 1H.

Great.

Thank you very much.

Paul Spedding of DKW, good afternoon.

Afternoon gentlemen.

Just a quick small question on refining and marketing.

I'm looking at the UK segment, the delta, those of the first quarter is a small negative, yet obviously we had very strong refining margins in most of Europe.

Can you just detail what has offset the benefit that should have come through from that refining benefit?

Sure, I'll ask Fergus to answer this question directly.

Thanks John.

Paul, yes the main thing of what you said was a significant uplift in refining margins, but comparing to the second quarter last year, the offsetting effects were principally turnaround effects to the Coryton Refinery, foreign exchange, some of the marketing margins that were compressed as product prices and crude oil prices rose.

And finally, we were very proud of our ability to minimize the cost of goods sold in to our refineries through the trading organization.

There are some very strange effects on differentials in the crude market and the product markets, as you know, during this very strong period of prices in the second quarter that had some compressing effect as well.

Thanks very much.

John, can I just add a bit, the UK numbers of BP, because this is the center of the activity for all the businesses, but you see a much smaller volume refining and marketing, and petrochemicals.

The legal entities through which a number of charges are channeled are UK entities and that creates some volatility in the numbers that has nothing to do with the underlying performance of the assets within those areas.

It's the reason you see negative numbers when you had expected it to be positive.

Sure.

Thanks Paul.

Mark Goldman of Benchmark, good morning.

Gentlemen, good afternoon.

I had two questions, one virtually by way of a clarification.

I wonder if Byron might clarify whether the export duties and lab tax effects for BP TNK numbers that you quoted are on a pretax or an after-tax basis.

Second question John, is for you, with respect to some of the language concerning the dividend philosophy.

I have never I don't think heard dividend philosophy expressed in quite the terms that you did, in terms of a total dollar payment being a function of the number of shares outstanding.

It would seem to me that this reflects some abandonment if you will, of any idea of a payout ratio and would rest on whether or not the share repurchase program is dilutive or antidilutive based upon whatever mid-cycle assumptions you are utilizing.

I wonder if you could help me analytically walk my way through this issue.

Thank you Mark and thanks for the question.

I don't agree with the question and let me be clear.

The way we think about payout ratios is a percentage of the total net income of the company, it's one of the things we look at.

And, so that percentage of net income has to be divided by a certain number of shares.

If the number of shares get down, seems very reasonable, therefore the dividend per share can go up.

So we haven't abandoned, absolutely we haven't abandoned nothing whatsoever.

This is completely a matter of mechanical arithmetic.

Now, maybe Byron can answer the first part of the question.

Mark, you are absolutely right.

The export duty is deductible for income tax purposes and I have incorporated that into the numbers that I gave you.

So, this would be on a net income basis, the $55m and the $65m are referred to.

Thank you, Browne.

Thank you Mark.

Irene Himona, Morgan Stanley.

Good afternoon.

Just a quick question on the after disposals.

Your first half disposals of about 3.5b pounds appeared to have more or less met your annual target for this year.

Could you perhaps update us on what we should anticipate for the full year '04 and perhaps, going forward, what will be your normal run rate for '05 and '06?

Thanks.

Thank you Irene.

We have been pretty successful this year and we had a good start with various securities we sold.

We would expect to be well ahead of the 3b pounds to 4b pounds range that we gave you, will be well ahead of the 4b pounds and it looks like difficult to say exactly where but that may be up to 1b pounds of where beyond where we are at the moment.

But it will vary depending on the timing of deep deal completion of the cycle.

So we set the steady TAT of around about a billion dollars per annum was the thing to factor in and we've got no basis upon which to change that at the moment.

Thank you.

And that excludes the impacts of the IPO instantly from all of instant derivatives, too early to tell what the cash relationship there is.

Thank you.

Can we take Ian

, please, of UBS?

Ian, good afternoon.

Good afternoon, gentlemen.

Just a couple of quick questions about Trinidad.

I wonder whether you could tell us whether the plant is now fully back in operation after the explosion you had in the second quarter?

And also what the likelihood is of a potential new LNG in Trinidad or you've have been discussing with the government, if there is any progress on that?

Tony.

The plant is on, I'm pleased to report now, back and fully operational -- it was down for a couple of weeks.

We had a plant shutdown and as we broke one of the trains back home we had a problem with it.

But it is now fully functioning, fully operating, and everything is running normal.

In terms of the future, I think the next step is likely to be what we referred to as a virtual LNG train through the debottlenecking of what will be the four trains, once train four is completed at the end of 2005.

And beyond that, we certainly need to go and find some more gas to involve combined in effect will be train six and we are doing that by way of recommencing our exploration program through the second half of this year and into next year.

Is it possible to say what the debottlenecking could add in terms of volumes?

It's effectively another train.

Okay.

Thanks Ian.

Ian Armstrong, Brewin Dolphin, good afternoon.

Good afternoon, two quick questions.

One is, all the factors that effected the refining marketing margins in the first half of a lesser or greater impact on profitability in the remainder of the year and what I am trying to say is that the sort of the difference between the Global Indicator Margin and actually what you achieved.

And the second question, also to do with the plant shutdowns, either within the refining and marketing or in E&P for the third quarter.

Can you give us a state on those?

Thanks, Ian.

I will ask Byron start of the answer.

Ian, the Global Indicator Margin is just that, it's an indicator and it doesn't match up perfectly with our own refining configuration.

Therefore, it can overshoot or undershoot.

So there is no ability to really get a calibration of what its going to do one quarter to the next, given that it has indicated margins more than what had been achieved in this quarter, the more likely effect is that there will be a correction in 3Q or 4Q that there is always the possibility that it will go even further than is built into the numbers today.

So, sorry that is a long-winded way of saying we really can't tell you, we will have to just wait and see.

What I was trying to get was the things issued on the year control, for example, at the closure or the downtime at Texas refinery or the lubricants, etc.

Is that

the same sort of impact of profitability to the rest of the year?

Well, I think I understand what you are getting at.

It's simply in this that there is a pattern of turnarounds and shutdowns over the year.

Taking the year as a whole, it is not dissimilar to a prior year, in my view.

We can get back to you on the details of what's actually happening about quarter-to-quarter, but in sum, it's not particularly different from prior years.

Great.

Thank you.

Can we just take one question from the web, from Paul

of Wellington Management.

I believe you've mentioned that capital spending would be 1b pounds lower in '05 and '06 than this year.

The question is, is this due to divestitures or you actually cutting back?

If you are cutting back, can you tell us in what areas you are doing this?

Paul, what we are actually doing is getting to a steady-state level of capital expenditure, that being a bit of a bubble in capital expenditure over the past, primarily to do with infrastructure spending and this mean so much infrastructure you can build and also a significant acceleration of projects.

We want to get back into a normal pacing.

The levels we indicated in March are good for a long-term growth of the Company.

Great.

Thank you very much.

Angus McPhail, please, of ING.

Angus?

Yes.

Just a very quick question, if I may, on TNK-BP, could you possibly give us some guidance as to what cost or synergy benefits you have identified to-date from that joint venture?

And if you are not prepared to answer the question, could you possibly tell us when you will be in a position to come out with a final cost and synergy number?

Right.

Yes, let me deal with that, Angus.

I think the reality is that, this combination was never about cost and synergy benefits.

It was about deploying BP's corporational capability in terms of technology and business process and Western governance, and all other things that you would expect us to deploy to this vehicle.

And we are seeing the benefits of that in the 12% year-on-year volume growth, and we expect to continue to see significant volume growth, going forward.

So, if you want to look at the benefits, it's a revenue benefit.

It's okay.

I mean the reason I asked the question is the fact that TNK-BP actually employ the same number of people BP do, on a global basis.

So, the obvious cost benefit would be to actually employ some de-manning with some TNK-BP, why you are not doing this?

I think, you have to understand all that 100,000 people is.

It is of course a reflection that TNK-BP has 70 service companies, it does all of its own drilling, all of its own seismic acquisition, it runs the local hospitals.

It is a very different situation.

It is undoubtedly true -- that will evolve over time.

And over time, and I think time is, a decade in this case.

We will see an evolution of not only TNK-BP, but the whole of the Russian oil industry.

But it's not appropriate to compare BP manning levels to TNK-BP manning levels.

We conduct completely different activity sets.

To do a life-to-life comparison, you would need to include all of the contractor headcount that we use to conduct our operations.

Angus, in my point of view, we did find and we have executed some synergies vis-a-vis TNK and Sidanco.

That was winding the old Sidanco company, that's pretty well done.

The overlaps were reduced, and that's happened.

Then why the question of employment in Russia, I can only completely concur with what Tony said.

The main impact here though is to get better efficiency and better cost, is something, which is very closely attended to by the management.

But I think it would be very counter-productive to set benchmarks on a Western style.

Very good.

Thank you.

Great.

Thank you.

Could I take a question from Matt Pickering of Institutional Capital?

Good morning.

Gentlemen, I had one quick question please for both Lord Browne and Mr. Tony Hayward.

I was hoping you might have any kind of comments updating your opinion of the Bolivian gas referendum, and given your position in the Pacific LNG consortium, whether you feel that in any way, while are you to potentially realize some of the export potential from the Bolivian gas in the relatively near or medium-term future?

Thank you very much.

I'll deal with this one, Matt.

I think the first thing to remind everyone is that we have a very small interest here, which is held firstly through our interest in Pan American, which itself holds an interest in the Chaco company in Bolivia.

So, our net interest is very small.

I think we have taken a view for some time.

There was a lot of things that needed to occur for this project to move forward, and it's not been on any plan we've looked at in a sort of five-year time frame.

I think until the situation in Bolivia stabilizes, and we can have greater confidence in the legislative framework, and then fiscal regime that we will be appraising under is, it's unlikely to move forward.

I think the results of the referendum could be seen as encouraging, but I think it's very early days.

Given then the magnitude that current events represent to BP, and given the magnitude if we represent some of the other parties, does it make sense to kind of conceptually think about that ownership interest as potentially being divestment

?

As we've said many times, we didn't discuss divestment options or acquisitions until such time as we've completed them.

Okay.

Thank you.

Thanks.

Collin Smith, CSFB.

Good afternoon.

Good afternoon, gentlemen.

A question on buybacks, if I may, just where they are, given how strong your cash flows have been and given the fact that you're a couple of percent below the gearing ratio that you will be in towards the end of the year.

Just to clear things on -- even if you rely for a weakening of oil prices and perhaps refining margins through the balance of the year and with the step-up in CapEx, it still looks on the current run rates as though you might be below the bottom end of you gearing target.

Does that imply you might pickup the rate at which you would repurchase shares in order to ensure that you're at the lower end of the 25% to 35% range?

Collin, we're not going to forecast for you the amount of share buybacks we're going to pursue in the second half of the year, though we will do as John said, which is to respond to the cash flow as it accrues and we're hoping that the very benign environment in which we're operating persists across the last six months of the year.

The one thing you need to remember and I've shared this several times with those who tune into this webcast, which is that we have a seasonal swing in working capital that occurs at the end of the calendar year, which in its own right tends to move the gearing rate up about 2%.

So, we're -- although it looks like we're below the rate right now, all other things being equal, we'll return to the lower end of band at the end of the year.

So, we keep an eye on quite a number of things here, Collin.

All right.

I appreciate the working capital swing, we saw that last Q4 as well.

Perhaps I can just rephrase that, can -- we can be pretty clear that you will be at least to 25% at the end of the year, that way?

Collin, that would be our target.

Okay.

Great.

Thank you.

.

Good morning.

And good afternoon.

I have a question on the economics of natural gas.

Can you just give us a bird view on how you look at natural gas economics in Egypt, in Algeria, at Trinidad and Tangguh project, and your total investment again on all these projects?

Great.

Thank you Farogat.

Let me ask Tony to answer this question.

Tony?

I suppose -- I think the first thing here I would say is that we all were looking at of course Farogat, in terms of what's the netback we can get to the wellhead.

That's the way we look and think about the value chain.

The netback to the wellhead plus the marketing margin we can make by optimizing LNG position into the markets in which it's going, and we've clearly built so over the last five years.

A quite material positioning to the Atlantic Basin LNG market and are in a position now to switch supplies from what used to be point-to-point to point to the most -- the best place to get the highest netback and to make a marketing margin.

In terms -- so that's sort of how we think about it -- in terms of the -- those four things.

Let me see if I can go through them one by one.

In Egypt, we have -- and I don't know the numbers of the top of my head in terms of the capital employed we have, but we have a 25% share of domestic gas business, and in the back of very strong exploration results in -- over the last year we now have the basis to create a material LNG business.

We've made a commitment to defer a part of the first train of LNG in the Eastern side of the Nile Delta and have an option on the second train and certainly have sufficient gas resources there to more than fill the second train.

So, we've that sort of an LNG scheme for the future to add to the domestic gas position we have.

In Algeria, we have -- this is pipeline gas to Europe today and we've started out the In Salah facility in the last month and it is now ramping up, first gas sales are going to Italy.

And our investment in Algeria is of the order of around $2b.

In Trinidad, I think, we've rehearsed this with you many times, I think it's probably -- the crown jewel in our gas portfolio today given its geographic position adjacent to the what is undoubtedly the most attractive market in the world today, the US market.

It's low cost gas, we have the fourth Train is under construction, will be in operation by the end of 2005 and that is one of the places where we can optimize the supply into the market in an very appropriate way.

In terms of Tangguh, we have yet to sanction that project, we would expect to sanction it towards the end of this year.

We've completed a series of gas sales agreements in support of it and have got most of them necessary approvals and agreement with the Government of Indonesia and would expect some moving forward towards the end of the year.

of rather unstructured summary in slide 11, it would be very helpful.

No, I am not sure.

That -- answer, I don't know quite how we answer your question, but I think I'll put it like this.

In thinking about gas, we think still rather conservative, we've passed the normal as I believe, was anywhere doing consistently.

The price of gas has to be thought of an relationship to the price of oil.

And therefore we start on that basis where $20 means $3.50 Henry Hub.

We then look at that the specific dynamics of location differential available market new margin and then use this as a way rank ordering the projects we look at before we consider risk in other risks such as the political, durability and things like that.

But, this gives us a starting point to examine what we are doing.

Of course we make sure the projects that we enter into are either have to have high instantaneous returns, or have to have the capability of expansion in order to get those returns in due course, having once captured the market.

I don't know whether that gives you an answer to your question?

Very much, Tom.

Thank you very much.

Right, thank you.

But then I think there is time for one last question, Jason Kenney of ING.

Hi, three short assets questions, if I may.

One is on Ascot and what's really happening there?

There was the potential to build either a pipeline or to ship gas from the Shoal field, and in addition based on the project timing.

The second one was on the BP Rosneft venture on Sakhalin and the proposals to finance the exploration there.

What is the possibility of having to spend development CapEx in the next three to four years?

And thirdly, just on the Azeri gas projects, I am sorry this is -- hope you got a big project, but any update on shortening and the potential for further gas exploration in that field?

Great, too many questions.

Let me deal with all works, let me see, from East to West.

If I start with the Sakhalin, we've -- as you know, we have an exploration joint venture with Rosneft, we've studied that well.

Any discussion around this element will clearly be dependent on whether we find anything in the well, we think it's reasonably perspective block, but it's -- this is frontier exploration and we won't know until later in the year.

So, really that is a question for the future.

In the event of any development, it would several years down the track frankly, this will take sometime to both first understand and then figure out what would be involved.

In terms of Shoal, which I think is the question about -- that has got -- we're still quite a long way off being in a position to sanction that project, it's still being engineered and certainly wouldn't anticipate sanctioning it before the second half of 2005 at the very earliest if then, and the remains much debate about the most appropriate export route and thirdly on Shah Deniz, we are making very good progress.

As you know we are laying the gas pipeline at the same time as we do BTC.

So, some of that has been done the river crossings for example have been laid at the same time as we lay the BTC oil line.

Once we have completed the BTC we will lay the gas pipelines sort of going back the way, in terms of the project we completed the drilling of the wells in the field, the facilities on the construction in Azerbaijan and everything is on track for first gas in 2007 end of.

Ladies and gentlemen, thank you very much for joining this afternoon.

Thank you for your questions.

I hope we've answered them.

If not, we stand always available to answer these or any other questions at your convenience.

Thank you very much for joining us and good afternoon.