英國石油 (BP) 2003 Q1 法說會逐字稿

Welcome to the BP first quarter results conference call.

I'm going to hand the call over to Mr. Fergus McCloud (ph).

Please go ahead.

Good afternoon to those of you listening in Europe and Asia.

And good morning to those in the Americas.

I'd like to welcome you to BP's first quarter 2003 conference call.

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

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

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

If you're listening on the telephone, the slides are available to download from the investor center on our Web site, BP.com.

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

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

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

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

Actual results may differ from these plans or forecast for a number of reasons such as noted here.

I'm now joined by Byron Grote, BP's Chief Financial Officer.

Byron will provide a brief overview of BP's first quarter financial and operating results, and an update on the strategic milestones passed in the first quarter.

With that background, let me turn the conference call over to Byron.

Thank you, Fergus.

And welcome to those joining us over the phone or Internet.

I'll begin my remarks with a summary of the first quarter trading environment, and then review the group financial results for the quarter.

I'll go on to describe the progress each of our segments is making to implement the plans and strategies we discussed in February.

Finally, I'll close with a review or financial framework, after which Fergus and I would be happy to take your questions.

Rating conditions in the first quarter were strong overall.

Our average liquids realization of nearly $30 per barrel was up more than $11 compared with the year earlier and up more than $5 on the fourth quarter.

This was driven mainly by supply concerns related to the war in Iraq, together with disruptions to Venezuelan and Nigerian exports.

Our average natural gas realization of $3.87 for 1,000 cubic feet was $1.60 higher than the first quarter of 2002, and a $1 higher than in the fourth quarter.

This reflected increasing supply constraints and a colder winter in North America, which drove gas prices above fuel oil parity as industry production remained flat and seasonal inventories were drawn down.

Higher prices at Henry Hub on the U.S.

Gulf Coast, were partially offset by widening regional differentials between Henry Hub an western U.S. producing areas.

Gas prices for our North Sea volume also increased but not to the extent of those in North America.

Taking oil and gas prices together and weighting them according to our production volume, our average realized hydro carbon price rose by around $10 per barrel of oil equivalent compared to the first quarter of last year.

Turning to the downstream, our indicator margin for refining of $4.52 per barrel rose nearly $3 compared with the first quarter of 2002.

Although not shown, retail fuels margins were also up significantly from the very low levels seen in the first quarter of 2002.

These first quarter margins were supported by low industry inventories for crude and refined product.

Petro chemicals margins remained weak as fee stock prices rose faster than prices for most products in our portfolio.

The first quarter indicator margin estimated at $90 per ton was up slightly compared with a year earlier.

It has continued to weaken since the middle of 2002.

Turning to current trading conditions, although oil prices have declined by more than $5 per barrel from the first quarter average, U.S. gas prices have remained relatively firm.

These lower oil prices have relieved some of the margin pressure in our market facing businesses.

Our ability to sustain this hinges on many factors including how overall economic trends impacted demand for our products.

With hydrocarbon prices and margins for most of our main product up so significantly in the first quarter.

BP's financial result were strong particularly when compared with those of a year ago.

The pro forma results of more than $3.7 billion was our highest quarterly results ever.

And that's 136 percent on the first quarter of 2002.

On a per share basis, our first quarter pro forma results of $1 per ADR was also a record.

Our first quarter replacement cost profits which includes special items and acquisition impact was 3.7 -- $3.1 billion.

Our first quarter historic price profit which also includes disposal and inventory gain was $4.3 billion.

These figures are both more than triple those in the first quarter of 2002.

And are also quarterly records for the company.

The improved results flow through to cash flow with our first quarter pre tax cash from operations of $6 billion, up 64 percent on 2002.

As mentioned in February, the board set the dividend quarterly based on a variety of factors, including our competitive position, present earnings, long-term growth prospects, and cash flow.

Our first quarter dividend of 6.25 cents per U.K. share was up nine percent in dollar terms compared with last year.

Our first quarter pro forma return on average capital employed was 20.4 percent.

This is more than double the 9.9 percent earned in the first quarter of 2002.

These are strong results.

They are driven largely higher prices and margins as I noted earlier.

But they also reflect performance improvements in our underlying businesses.

I'll return to this in more detail momentarily.

I would first like to place the quarter in a competitive and historical context.

This slide shows BP's pro forma return on average capital employed against those of our principal competitors over the past three years.

All results are calculated using consistent approach which I discussed at length in February.

The details of that calculation, which we believe reflect industry best practice on our Web site.

The industry price and margin cycle is evidence from the chart.

BP's position within the ban reflects and will continue to reflect competitive differences in portfolios and strategies, including the continued impact of our distinctive investments to build five new upstream profit centers as indicated in February.

Since BP is the first of the competitor group to announce its result this quarter, a competitive comparison of our 1Q return is not available at this time.

This slide shows the main factors driving the more than doubling of our first quarter pro forma results from $1.6 billion in 2002 to $3.7 billion in 2003.

Our liquids realization increased our results by around $1 billion post tax.

This is net of a $70 million year-on-year impact from moving unrealized profit in stock or UPIS as announced in our stock exchange announcement.

Stronger GAAP realizations added a further $650 million after tax.

Improved refining and marketing margins contributed an additional $400 million post tax for the year-on-year increase.

This reflects a rebound from severely depressed conditions in the first quarter of last year.

It's slightly less -, from the change in generic industry indicator margins due to factors unique to our asset configuration and pressures on some commercial businesses.

Our environmental effect were up around $100 million after tax from other factors.

These include improved margins in our NGL and petrochemicals businesses.

Operating and financing factors between the two periods netted out.

On the cost side, the weaker dollar compounded normally inflationary pressures.

We also experienced a nearly $100 million year-on-year increase in pre tax pension and post retirement benefit charges.

Note that I'm describing on this on a pre tax basis consistent with the $300 million full year increase I mention in February.

The absence of Rural Gas (ph), which we sold last August, more than offset the additional month's contribution from Ava (ph).

Offsetting these negative pressures, we continue to improve underlying volumes and unit costs.

Upstream delivered an all time production record.

Petro chemicals also achieved a volume record despite weak demand in some markets.

In short, our portfolio was well positioned to benefit from the first quarter business environment.

And we continue to improve our business fundamentals.

I'll discuss individual statement results momentarily.

But to complete the group earnings picture, I'd like to make a few comments about financing and tax.

Over the last year, we have reduced the average interest our debt by 0.7 percent, and reduced our debt by $4.5 billion.

This generated $100 million pre tax IMPER (ph) savings for the quarter.

We also reduced our effective tax rate by one percent from 35 percent in 2002 to 34 percent in 2003.

This more the offset structural pressures from the expiration of section 29 tax credits in the U.S. and fiscal changes in the U.K.

North Sea and saved us $60 million.

Before moving to segment results, let me quickly review our special and exceptional items for the quarter.

As my colleagues and I discussed in February, we are continuing to improve the business through divestments and restructuring activities.

This creates one time earnings impact that are not representative of our underlying business results.

U.K.

GAAP classified some of these as exceptional items.

Consistent with industry practice, we choose to highlight and exclude other material items as special (ph) in our pro forma discussion -- disclosures.

This chart highlights our track record since the start of our major integration and consolidation activity in 1999.

As shown, our first quarter pro forma results exclude more than $200 million of net positive, pre tax, specials and exceptionals.

This includes disposal gains totaling $400 million partially offset by restructuring and impairment charges totaling around $160 million.

Consistent with past practice, I am showing this information on a pre tax basis.

That's the first quarter gain shown in the chart, does not include a further $130 million benefit from non reoccurring income tax savings related to restructuring activity which we also chose to exclude from our pro forma results.

As I indicated in February, we expect our full year 2003 specials and exceptionals to remain a net positive.

You may recall this slide from John Brown's (ph) remarks in February.

To summarize our strategy is designed to create value from a distinctive set of opportunities bias towards the up stream.

We seek to improve the quality of our portfolio through a disciplined approach to long-term investment and divestment.

We manage the level of activity to balance cash generated with cash used over time.

Based on a set of standardized assumptions managing through peaks and props in the price and margin cycle.

And we simple allocate capital and certain costs to optimize gross margin.

Collectively this should position us for success and enable us to deliver a balance of long-term growth and competitive returns.

That's our overall business model.

Now let me update you on how each of our segments is implementing the strategies aligned with this model.

In the upstream our track record of industry leading exploration success continues.

We have all ready announced the discoveries of Hortensia and Acacia in Block 17 in Angola, and still have the majority of this year's exploration drilling activity ahead of us.

We've sanctioned three of the four remaining major projects reflected in the build profile show in February.

These include Jacque Denis (ph) and Azerbaijan as well as Greater Plutoni and Dalia in Angola.

In addition, though it's part of the build portfolio, we sanctioned Rhum in the North Sea.

As I mentioned earlier, our first quarter production of $3.6 million barrels of oil equivalent per day was the record.

And up more than three percent on the same quarter last year.

I should point out that the second quarter production will reflect the impact of previously announced disposals in the North Sea U.S. and elsewhere.

This is expected to impact 2Q by over 100,000 barrels of oil equivalent per day.

Following completion of the planned acquisition of 50 percent of T&KVP this summer, we expect reported volumes to resume their upward trend.

We expect the overall outcome for underlying volume growth for the year, that is before M&A activity remains in the zero to three percent range indicated in February.

In the first quarter, we completed portfolio transactions involving Trinidad and Tangguh interest, the Columbia JDA Asset slots.

And the disposal of assets in the Gulf of Mexico shelf as well as other minor U.S. properties.

We have since closed on the disposals of 40 and a North American oil package.

And have also announced disposals in Venezuela and the Docking Ketzmet (ph) area in the North Sea.

Our completed and contracted upstream disposals today total $3.3 billion.

In gas power and renewables, we continue to focus on maximizing value through both gas sales growth and marketing improvements.

Results are all ready apparent in North America gas marketing, where sales volumes improved by 35 percent year-on-year.

Reporting our strategy of capturing market ahead of supply, we commissioned a new gas fired power plant in Bilbao Spain in which we have a 25 percent interest.

This plan is associated with a new LNG import terminal due to be completed later this year.

We also launched the second of three new LNG vessels which will provide us with more marketing flexibility.

We continue to capture the margin available in NGLs despite pressures from high gas prices.

Our strong first quarter results reflects robust prices on winter propane sales, which more than offset volume reduction and lower margin products such as -.

Progress also continues in building our renewals business.

Around 1Q, we rolled out an innovative BP branded fuller offer for the California market.

In refining and marketing as well as across the rest of the group, we've been changing our performance focus towards the optimization of gross margin.

This transition, which we mention in February is still at an early stage but is all ready providing us with many useful insights.

We expect it to become our primary means of describing our business activity.

Turning to operations, in the first quarter, we rearranged more than 600 sites to the BP Helios (ph) logo, bringing our number of Helios (ph) sites to 11,000 worldwide.

In February we announced that we'd be investing $300 million on clean fuel projects in 2003.

In the first quarter, we completed three units at a refineries -, in the U.K., in Whiting and Texas City in the U.S.

These units provide additional capacity to meet customer preferences for clean gasoline and diesel fuels in our regional networks.

We increased our refining throughput by one percent compared with the first quarter of 2002.

And we achieved this even as we completed 40 percent of our planned full year turnaround activity in the first quarter.

On the portfolio front, we have now completed the divestments mandated by the German federal cartel office when it approved BP's acquisition of Beba (ph) in April 2002.

These include the sale of OMV, the sale to OMV, of our stake in the Biurenal refinery (ph) and the trans Alpine pipeline, plus retail stations in Germany, Hungary and Slovakia.

The sale is conditional and regulatory approvals an the non exercise of certain preemption rights.

In keeping with our strategic intent to concentrate on seven core products in petrochemicals during 1Q we completed the disposal of Vermicastro (ph) chemical businesses.

We also announced our intention to sell our interest in our global specialty intermediate businesses.

At the same time, we continue to grow our core products.

In the first quarter, we successfully started commercial production from our new PTA plant Juihai (ph), China.

In Europe, we announced our intent to build a new world scale PTA plant in Gaya (ph), in Belgium.

In -, we began and -, expansion project and Chocolate Bayou (ph) in Texas.

We also sanctioned the building of our major petrochemicals complex in Shanghai, China.

We expect this project to start production by early 2005.

All of these steps deepen our position in our core products.

And during 1Q, we continue to reduce our cash fixed cost per ton of capacity as we indicated in February.

Volumes, as noted earlier, we're at record levels.

Our joint programs to integrate the assets and of BP, Sedenko (ph) and T&K continues.

We have identified the members of the T&K BP Board of Directors, selected equally from BP and Alpha Axis (ph) for Nova.

As well as the venture senior management team.

These deployments are provisional subject to transaction completion which remains on track for this summer.

Around the completion date, we aim to provide further information including details about T&K BP will be shown in BP's published results.

For now, our main focus is on obtaining the necessary approvals by relevant competition authorities and the boards of the relevant shareholder companies.

And I'm ensuring a successful integration that lays the groundwork for T&K BP's long-term commercial success.

We are of the high level of interest that many of you have shown in this strategic investment.

Let me give you a couple of operational highlights of recent performance.

In the first quarter, the Sedenko (ph) grew its volumes by more than 10 percent.

T&K grew its volumes by a similar amount.

These figures are ahead of our forecast.

And the share of crude volume exported that's benefiting from the strong global oil price environments remains constant at around 45 percent.

In summary, our integration work and results to date confirm the assumptions behind our decision to proceed with this combination.

We remain excited about the value we expect to provide for BP shareholders.

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

We use debt as our primary near term shock absorber.

This gives us flexibility to sustain our underlying business strategies and to time our acquisitions and disposals based on opportunities and market conditions.

A single quarter is really two short of a time observe the full strategy in action.

But elements can be seen in the comparison of first quarter cash flows in 2002 and 2003.

Each pair of ours represents a single quarter with cash sources on the left, and uses on the right.

The period shown contrast the relatively weak trading conditions of last year with the relatively strong trading condition of this year.

This change is most evident in the differences in cash from operations shown here in green which grew from $3.6 billion in 2002 to $6 billion in 2003.

As we discussed in February, the 2003 figure was impacted by a $300 million cash outlay to fund our U.S. pension plan.

This is around half of our expected full year funding amount.

These figures are shown before interest and tax consistent with U.K. accounting standards.

As shown as a use of cash in pink, interest and taxes in the quarter low relative to pre cash tax flow.

This is due to the year-on-year savings I mentioned earlier as well a normal quarterly tax payment phasing (ph).

In spite of the operating cash flow fluctuation we maintain first quarter organic cap ex at around $3 billion in both years.

Our first quarter spending last year, also included a $1.5 billion cash outlay to fund the initial phase of the Beba (ph) acquisition shown here in orange.

In early 2003, our portfolio actions shifted to disposals of properties non strategic to BP.

That's arising on strong buyer interest during a period of high prices.

We generated $2.5 billion of disposal proceeds shown in yellow.

The remaining uses of cash are distribution to shareholders via dividend and buyback.

Our first quarter of $1.4 billion is up nine percent on the first quarter of 2002.

In addition to dividends, we brought back $1 billion of EP shares during the first quarter.

This chart summarizes our first quarter organic capital expenditures and investments against the full year plan figures we set out in February.

We expect T&K BP to be self funding following this formation so that I twill not impact our organic cap ex and disposal ranges for the year.

We invested $2.9 billion in the first quarter, including $2.1 billion in the upstream where we are building the five growth areas highlighted in February.

Spending is consistent with our 14 to $14-and-a-half billion indicator range for the year.

Our first quarter disposals across all businesses totaled $2.5 billion as I stated a moment ago.

And we all ready have deals in place that are under discussion for another $1.8 billion of divestments.

Due to the strong market interest we're receiving as we upgrade the portfolio and completed the mandated Beba (ph) downstream disposals, our full year divestment proceeds are likely to be at the upper end of the three to $6 billion range set out in February.

Our strong first quarter cash flow allowed us to reduce our net debt ratio or gearing (ph) below our 25 to 35 percent target range.

As shown on this chart, we have generally maintained gearing (ph) in the bottom half of the range since the BP Amaco (ph) merger.

This has given us the flexibility to pursue strategic opportunities such as acquiring Beba (ph) in the first half of last year, despite the temporary dip in downstream margins.

As in early 2000, we expect the current low level of gearing (ph) to be temporary.

Following the initial chance outlay for T&K BP we expect gearing (ph) to return to the bottom half of the target range later this year.

In summary, our first quarter results reflects the balanced framework of delivering value we discussed in February.

This includes value growth through operating efficiency gains, and a disciplined and focused investment program which underpins a progressive dividends policy.

Our dividend growth remains highly competitive, building on a 20 year track record of growth in real terms of three to four percent per year.

When circumstances warrant we'll supplement returns to shareholders by returning surplus cash to investor via share buyback.

We have now completed $1 billion of the $2 billion buyback program announced in February.

At our annual general meeting last week we had obtained shareholder approval to sustain buyback beyond this should circumstances warrant.

That concludes my prepared remarks.

Fergus and I would be now happy to take your questions over the phone lines or the Internet.

... would like to ask a question they may do so by pressing star one.

To cancel your question, press star two.

All right.

We'd like to take the first question from Doug Harrison (ph) in the United States.

Are you there Doug?

I am.

Good morning, guys.

And congratulations on some very good numbers.

My question is about refining and marketing.

And in refining and marketing, your results were pretty close to record levels for our first quarter, but in light of the strong conditions that we had in refining and marketing, it seems that they may have been better in the U.S. and maybe in Europe.

And so my question regards your comments on down time that you had in the period, specifically whether you could elaborate on the cost, your opportunity cause what is was related to maintenance to Carson and Whiting in the United States and in the European system as well, which may have held results back in the period.

And as part of your answer, Fergus, can you guys remind us how much natural gas you purchased in the United States aren't in business on a daily basis as well?

OK.

Doug, let address first the refining and marketing question.

As you know, we did have a very large amount of turnaround activity in the U.S. during the first part of 2003.

That was further exacerbated by the Whiting fire which then led us to take a look at whether that problem that we encountered there was systematic across other refining areas.

So in total we had our refineries down for a much longer period than what has normally been the case in the first quarter of the year.

The overall impact of that on the U.S. refining results is in the order of magnitude of about $50 million.

OK.

As far as the European system goes, it looks like it would be something of a similar level.

OK.

Sorry.

Sorry.

I'm checking some numbers here, Doug.

No it's -- the impact in Europe was much lower based upon there being really nothing of a truly material nature that was impacting our results there in the first quarter.

OK.

Doug, to answer your question about the sensitivity to the higher gas prices in the quarter, the full year financial impact there if those gas prices would be the same would be 50 to $60 million.

We'll get back to you with the exact volume metrics of that.

OK.

Great.

Guys.

Thanks a lot.

We'll now move to the U.K. and we'll take a question from Neill Perry (ph) at UBS Warburg.

Thanks very much.

I'd like to follow up actually on the downstream, and the U.S. downstream.

You mentioned there that figure of 50 million.

And I noticed if you just look sequentially from the fourth quarter of last year in to the first quarter of this year, you've got a fall of about 40 million.

Yet, you have got this very big move out on your refining margin on your own indicators.

And I understand that marketing, although you don't show it, Q4 to Q1 actually did improve.

Could you just break down for us refining versus marketing as you have in the past?

And tell us if there are other moving parts in there, whether you've got any issues in terms of trading?

And then Byron, I was just wondering, given that we've got these very strong margins in the first quarter across the world whether you can comment on where you see refining and marketing in Q1 versus what you would see as being your mid cycle refining and marketing conditions.

OK.

As far as the breakdown in 2003 between refining and marketing, on an RCOMP basis, refining was $570 million, marketing $284 million.

So a total that adds together to be 854.

So a ratio of about two-thirds on the refining side, one third on marketing.

As far as underlying or mid cycle or through cycle results I'm pleased that you asked that question.

So I can just reconfirm that on an underlying basis, we have a -- it's -- the term debt we are no longer using.

In fact, John made it very clear when he made his remarks in February that it is a way of looking our business which we found to be increasingly complex clouded with so many judgements as that it was certainly not auditable under a Reg G requirement.

And was, I think, putting too much of a burden on BP to take these judgements.

We are trying to provide now a range of information for you, a range of indicators which you can use to divulge whatever you believe is an appropriate return based upon standard assumptions that you might choose to use across the range of competitors.

OK.

As far as how things fit versus history, on the refining side, it was strong.

And on the marketing side probably best categorized as being normal.

Right.

So there's nothing -- there's no other significant moving part.

... refining contributed 149 million ...

In the U.S.

... quarter 2002, and marketing 138.

And the comparable numbers for the fourth quarter of 2002 are 263 refining and 324 marketing.

Now returning to the United States, back so we can take a question from Tyler Dann (ph) at Banc of America.

Yes, good morning.

I wanted to discuss the lifting costs.

And if you could please go through how those moved both sequentially versus the fourth quarter and then year-over-year?

And some of the kind of qualitative auto controllable factors that you're trying to influence in terms of lowering those.

Our lifting costs were down.

They were down relative to 1Q and relative to 4Q.

And if Fergus can dig me up a number, I will share that with you.

But they were down over quarter-on-quarter comparison in both cases.

We have a whole range of activities in which we're trying to reduce such costs.

Part of this obviously is a direct consequence of the portfolio.

And we reduced lifting cost as a direct consequence of the upgrading activities that we're doing in the North Sea and in the United States where we are selling out of those operations which require a huge amount of effort to extract the oil and gas and provide relatively modest benefits to the corporation as a consequence.

So there's portfolio activity and then on a day-to-day basis with respect to existing operations, we are applying technology breakthroughs.

This is the sort of thing that advances day-on-day.

But over the course of a quarter, over the course of a year, over the course of a run of years adds up to make quite a material benefit.

So it's not one thing it's many, many things.

And it's the constant focus of attention of our teams in our mature areas in particular.

And coming back to the lifting costs on a 1Q-on-1Q basis the lifting costs were down by three percent.

And on a 4Q-on-4Q basis, 4Q on 1Q basis I will get back to you.

Yes, just to fill out that question on one point, Tyler, the four X (ph), clearly the weakness of the U.S. dollar did act against us in the quarter.

And the impact of that on year-on-year was about $50 million.

So that reduction that Byron mentioned of three to four percent in the lifting cost was despite the impact of foreign exchange which went against us.

OK.

Than you for that.

And if I could ...

...

Jeremy Elden (ph) at Lehman Brothers.

... the great success of the reusing program, I was a bit surprised that you had zero volume growth in your down stream.

Could you just tell us what other factors were holding back on volume growth?

And then noticed a pretty big outflow of cash in to working capital.

Debt is, in particular, very, very sharply up.

Can you tell us if there's anything particularly unusual going on there?

Well Jeremy, let me answer the second question first, as a CFO ought to be answering it.

There's nothing our of the ordinary here.

And I think, Jeremy, to look at these flows on a 90 day basis is to be applying a degree of precision to them that's unwarranted.

Obviously, the task of the team is to try to work with the minimum amount of working capital that they can to support their businesses, not on an every 90 day basis but on an every day basis.

There's so much movement in the price of feed stocks and products on a quarter to quarter basis here, that I believe that that would distort things under any particular situation.

So as of the price effect is the predominant factor rolling through here.

And I assure you that BP's management team and BPs employees are working to control its working capital exposure.

Yes, coming back to your volume point, Jeremy, obviously as you can see from the stock exchange announcement oil sales volumes were actually up year-on-year in every area other than the United States.

That was despite the fact that we found that the market environment was really quite weak in the quarter.

And it will be interesting to see as the results season go on, what the overall pattern that the industry experienced in the quarter was.

In the U.S. the factors at work were particularly weak demand that we experienced in the commercial businesses particularly in aviation and marine, which pulled down the overall numbers to give you that four-and-a-half percent decline that you see in the stock exchange announcements.

Right.

So it's ...

I would just add that we're very pleased with the interest in the downstream business which often times plays second fiddle to interest in the upstream...

...

Now moving to the United States we have a question from Mark Gilman (ph) at First Albany.

Go ahead, please, Mark.

Fergus, Byron good afternoon.

I wonder if you could tell, do you have a gas contract for Jacques Denis (ph) which you sanctioned in the quarter?

Jacques Denis (ph) is -- has indeed been sanctioned and is beginning construction.

But there's GAT (ph) contract that is underpinning that.

I'm not sure where you're headed on your question market, but there's no contracted volumes of gas from Jacques Denis (ph) that I am aware of.

There is no specific off taker for the gas on the project at this point?

Well we'd expect that much of the gas would be off taken in to the Turkish market.

But, as I said, I do not believe that there is a specific off taker associated with the project.

OK.

Could I just ask you what LNG profits wind up in your gas and power segment?

If you could just give me an example of the type of transaction that flows in to that segment?

Is that perhaps your purchase for resale associated with the arrangements you put in to place last year?

Or am I missing something?

Certainly, right, Mark.

Yes, the LNG trading which was LNG trading which was actually started to become more of a feature as we took delivery in the course of the second of our own LNG vessel is included in that.

And that is certainly a feature that we would expect to grow over time.

We also state re gas, -, some re gas in the LNG section.

But the principal elements of the upstream are still reported in our exploration and production division.

OK.

Thanks very much.

...more detail offline if that's helpful.

Thank you.

To the U.K. we go to a question from J.J.

Traynor (ph) at Deutsche Bank.

Good afternoon.

A couple of questions.

Firstly, on the downstream, what I'm trying to do here is annualize the returns from the downstream.

And using the group tax rates, that gets me through return on capital employed of just less than 10 percent, I would say actual perhaps even above your standardized conditions.

So my question on that, is what tax rate are you actually paying in the downstream?

And what trends do you expect there?

And I supposed what tax rate is assumed in the 12 to 14 percent target for the downstream division?

And then a separate and complete different question, I just want to double check the indications on dividends were for a three to four percent year increase.

In a target frame work of capital employed growing at about five percent a year with flat returns, my question is what's happening to pay out ration in that framework?

Let me take the second question first.

With respect to the three to four percent, that has been the track record over time.

And that is in real times not in nominal terms so three to four percent real.

Add whatever inflation rates you want to it.

And that's been the track record over time.

Of course, that's coming from a much smaller company.

And to being a company that is one of the largest industrial operations in the world.

What we indicated in February was -- has not changed over the course of the intervening 60 days.

And that is that we expect to be able to grow at constant conditions the underlying capital base of the firm at about five percent per year while we hold returns constant.

What John also said that's just one path of many we could choose to go down.

We could choose to build the firm faster.

It will probably be at the expense of high returns.

We could try to drive returns up.

It would undoubtedly be at the expense of growth.

So this signal to investors was a path that only one of many.

What we have done is aim to share with investors the underlying growth characteristics of the firm.

So as the firm grows in its earnings capability, the dividend will move in response to that.

And you have to do your own judgement on what you think inflation rates will be and what of the many paths we might choose to go down, we'll go.

But a dead center path is not totally inconsistent with continuing to deliver dividend growth of the level that you just described.

As far as the tax rate, and return on capital employed in the down stream, BP pays its taxes as one entity.

It doesn't pay it as a number of different entities.

So any sort of tax applied to a particular segment is again one of the many issues of judgement that are applied.

So the only thing I will -- can speak to is what is the underlying cash rate at the group level.

And we would expect on an annualized basis, although this can fluctuate depending upon the profitability and various other factors, that we have a cash rate of approximately 25 percent as opposed to the effective tax rate for accounting purposes which is closer to 34 percent.

So just to be clear then the return targets for that division of 12 to 14 percent of standardized conditions is that in the tax -- I'm sorry is that in cash rate of the 25 percent environment or the higher tax rate?

We apply a range of standard conditions as we're looking at this.

But to be clear, we don't look at returns within the individual segments on a regular basis.

And the indications that we provided are something that we only look at periodically, at most once a year.

So that's one -- it is the reason why we're not talking about specific returns in the individual segments during the discussion today.

That's right, J.J. so all of those statements that we made about return on capital employed, standardized assumptions were at the 35 percent tax rate.

And you're quite right, overall downstream in performance in the first quarter, despite the strength in refining margins were somewhat disappointing.

I think that reflects the weak economic environment and also the pressures that marketing was on in the face of higher prices later on the quarter.

So I think, -- for improvement there.

And on back to the United States we've got a question from Fred Leuffer (ph) at Bear Stearns.

Fred are you there?

Yes, good afternoon guys.

I have two questions.

One can you quantify the cost reductions in chemicals and in gas and power?

And secondly what was the net impact on production volumes of divestment, swaps and the Sedenko (ph) interest change on a year-over-year basis?

Can you say the last part of that again, Fred?

It was of Sedenko (ph) and whom?

Just divestment swaps and the higher interest that you have in Sedenko (ph) first quarter versus first quarter.

As far as the cost reduction, this is something that we are not going to talk about on a quarterly basis.

We've tried to share with you in the slide that talked about 1Q 2002, 1Q 2003 outcome, the various outcomes that were driving the results.

So there's a number of cost pressures that are coming in to place that I highlighted.

One of many of those is the higher charges for pensions and retiree medicals across the group as a whole.

So again that, we've had a lot of progress on unit costs.

And if we hadn't had a lot of progress on unit costs, as you look at the various elements that I described and summed them up, you'd find that the thing only comes in the balance, if there is indeed a fair amount of underlying cost improvement across the group as a whole.

And I think I will leave my remarks with respect to the business streams at that.

As far as the quarter-on-quarter production changes, Fergus has the numbers and I'll let him toss it over to you.

Fred, just let me fire away the numbers on that, there are a number of distortionary (ph) factors year-on-year.

There's the effect on volumes of higher oil prices which produce or entitlement volumes under production sharing contract, that's only $3,000.

There was a strike in Venezuela which reduced our production by about 20,000 barrels a day.

The net effect of divestments was about 6,000 barrels a day.

And on the positive side it was around 72,000 barrels of higher production from our higher entitlement from our increased interest in Sedenko (ph).

Does that answer your question?

That's excellent.

Thanks.

Can I just come back to one earlier point, Mark Gilman (ph) raised the question about gas sales.

And I apologize Mark that we didn't have the detail in front of us at the point.

It was, of course, in our press release of the 27th of February.

The gas sales agreements for the stage one development we've bought out of Turkey 6.3 bcm a year, Azerbaijan up to 1.5 bcm and GIOC of Georgia up to 1.8 bcm.

Stage one gas sales will be administered by the Azerbaijan gas supply company.

So those details, again, Mark, I'll go in to more detail if you'd like offline.

Coming back to the U.K. we've got a question from Mark Iannotti (ph) of Merrill Lynch.

Good afternoon, gentlemen.

Yes, a couple of questions.

First one is a simple one, the tax charge you gave some -- made some comments on first quarter tax charge 34 percent, why it remains in that area?

And can get through for the remaining three quarters of the year?

Or will it nudge back up to the 35-36 level?

And secondly, you stated significantly higher volumes than anticipated from both Sedenko (ph) and T&K in the first quarter, you know, an example of how well that transaction is progressing.

Can you tell us why, there in fact, was a surprise so soon after the announcement?

And how confident does that make you feel about the long-term quality of your forecast you have for that new entity?

Let me take the two questions in order.

As far as the tax rate goes, we're required under GAAP accounting to provide the effective rate tax rate for the year on a quarterly basis.

So we have looked at the year and concluded that 34 percent is the likely out turn.

Therefore 34 percent is a good number to be using on the second, third and fourth quarter projections.

As far as the very pleasant surprise that we've had in Russia, this is a consequence of the -- the work that is just normal bread and butter work of well work.

And things of a similar nature that's being applied to fields that are old, that have not been attended to with even the basic fundamentals for an extended period of time.

And through that very simple well work we have found that the fields have responded even better than anticipated.

If you remember we -- when we made the announcement, I had indicated that one reasons we went in to the deal was the progress that we had seen, the verification of the fact that the simple reservoir management techniques were likely to provide strong incremental volumes.

And this has progressed in the first quarter.

I would not want to leave you with the impression that you can now scratch out five percent medium term and put in 10 percent.

We still would project that five percent volume growth for T&K BP is an appropriate metric for you to be using at this time.

Although, as the first quarter has shown there may be, there may be a surprise on the upside.

Thanks.

All right, returning to the United States we have a question from Paul Ting (ph) at SALOMON SMITH BARNEY.

I have two questions.

One is more numbers related.

You indicated that you have to disposed it by the end of the second quarter if I remember it correctly, somewhere in the ballpark of about $3 billion of options added.

Does that mean that you've completed a bulk of your options divestiture by the end of the second quarter.

And secondarily, more a concept, have you had any discussion with the U.K. government related to your possible role in a post war Iraqi condition?

OK.

Well I'll take the numbers one first.

The answer is that yes, we have -- we'll have by the middle of the year, completed the bulk of the disposals that we had identified as we moved in to 2003.

But I want to reinforce that this is a dynamic process where we're constantly reviewing whether or not an asset is appropriate for the BP portfolio.

Are we going to invest to continue to maintain it?

Would it better if it was in the hands of another company.

So that's a dynamic process which doesn't just happen once a year or once every several years.

It's a dynamic process that the upstream management team is constantly reviewing.

So one would expect that you would continue to, I think Tony Hayward (ph) referenced this in February that you should continue to anticipate a twicing (ph) away of the bottom part of our portfolio over the course of the quarters ahead.

So I would not want to leave you with the impression that this is it for 2003, because may have more.

As far as Iraq goes, we've made it very clear publicly that we're looking -- John Brown used the term a level playing field.

And it is BP's position with respect to Iraq that anyone who enters any agreement would to do well oil and gas business Iraq needs to be invited there by the Iraqi government.

They need to be invited there on the basis of a level playing field, where it is clear from their perspective that it's at the best interest of the Iraqi people as opposed to as the best interest of a single company or another country.

W are indeed, as you would expect, as the largest company in Britain and as one of the three super majors in the sector, involved in discussions to understand.

Because we're involved in discussions where people are asking advice.

They want to seek our counsel not only in the U.K. but in other parts of the world.

But at this stage of the game, we have identified no roll, absolutely no roll for BP in Iraq.

...

Internet, we've got a question from Tim Whittaker (ph) of Lehman Brothers.

Tim's asking, could you comment on recent reports that T&K is seeking to acquire -?

Is BP's management aware or able to influence T&Ks plans in respect of service?

Well -, that we're not sure if you're referring to Suga (ph) or Slovnoff (ph).

But it's Suga (ph) we've got no knowledge of your comment about Suga (ph).

Clearly there's a lot of interesting stories that come out -, but that's not one that we've heard.

Our focus at the moment is closing our own deal.

We're on track to that.

As far as Slovnoff (ph), is concerned that's not included in the current deal.

We have worked with T&K to look at some of the -.

And we'll make a decision in due course if it makes commercial sense to do so.

But returning to the phone lines we have a question from Rod MacLean (ph) at CSFB.

Yes, good afternoon.

Two questions, please.

Can I get some comments from you in terms of the discount that you are selling your U.S. natural gas at relative to Henry Hub?

Clearly, it's been a very volatile sort of number over the last several quarters?

In the first quarter, a year ago, it was 22 cents in the first quarter of this year, of $1.26.

And I think we all know that there are several driving elements here.

Can you just help us out a little bit by maybe trying to give us some guidance on how you think that may develop going forward?

And secondly, I'd just like to come back to refining and marketing and just sort of clear up in my own mind.

In the release, you talk about marketing in the quarter being at normal levels.

Byron talked about it contributing about a third of total refining and marketing profits.

My question is under your standardized assumptions, what would the refining marketing split be?

OK.

Let me handle the first question.

We certainly don't attempt to sell any of our production at a discount, let's make that clear right up front.

The areas which are impacted are in the San Juan Basin and in the Rockies primarily.

And the growth in gas production in those areas have created infrastructure bottlenecks.

And those infrastructure bottlenecks have impacted, not only BP but have impacted the entire industry over the course of the last several years.

What happened particularly in the first quarter of this year, was there was the combination of a very cold winter on the east coast, and mid west, which allowed for very high Henry Hub prices.

So that cold weather drove Henry Hub prices.

At the same time it was a very mild winter in the west.

And the result of that was that gap which could not move easily to the east suffered a much lower price than would otherwise be the case.

Now there's new infrastructure being built in the San Juan and the Rockies.

We're participating in that, in some cases directly, in some cases supporting it through off take agreements.

And we would expect that that infrastructure would improve the position over the course of the next couple of years.

The Kern River expansion will be complete in the second quarter.

There's another expansion which we own that will be complete in the first half of 2004, a bunch of other lines which will go online in 2005.

So there is the investment going in there to over the course of the next couple of years slowly but surely relieve this.

I think you should view the very large deferentials that we saw in the first quarter, as a particular anomaly of the situation that exists today.

And the abnormal weather conditions that existed in the east coast and the west cost and not take that as a trend setter even if natural gas prices should stay at their current historically high levels.

And the price in doing that Rob, it's probably worth adding is significant.

We estimate that the impact on pre tax profit is that deferential between -, and Henry Hub to be in excess of $350 million.

So if we can get in just in at one quarter, so if we can -- if we've done that that definitely will have a big impact on results.

On your question on refining and marketing, what's the refining marketing split on the standardized assumptions?

The answer is we don't have a target blank level if you like of the relationship between refining and marketing profitability.

Byron mentioned the shift in refining and marketing focus on gross margin.

And as we do that work, what's unclear is that it's not about having some sort of arbitrary split between those two parts of the business.

That there's a process of optimization that will improve returns over time.

And so we're really not thinking in those terms.

Coming back to the United States we have a questions we have a question from Fadel Gheit (ph) at Fahnestock & Company, Inc. (ph).

Good afternoon.

My question is on volume.

You mentioned earlier on your conference call that volume -, will be lower in the second quarter.

Could you just go over quickly the reason for that?

And could you give us a forecast for second quarter and full year?

The impact that I described in my comments, which I think is what you're referring to Fidel is that the divestments that we have all ready completed will impact the production level in 2Q by approximately 100,000 barrels a day.

And this is the sale of the -- in the Gulf of Mexico.

This is the sale of Forties (ph).

This is the sale in the Permian Basin.

All of the sales in the U.K. and the United States that we referred to with an object associated with the transaction that we did swapping our position in the joint development area in Asia for additional interest in Cuzuiana (ph) and Pupiagua (ph) in Columbia.

So the net of those divestments and acquisitions led us to about 100,000 barrels a day of lower production in the second quarter.

Now offsetting that, as I said, was the expectation of having T&K BP as part of the company in the second half of the year.

And that will bring with it substantial incremental production.

... the summary answer to your question is Byron mentioned earlier the underlying volumes, that's before merger and acquisition and the -, activity, we still remain -- I believe we'll remain in the range we described on February 11, north of three percent.

There will be a dip in the second quarter as those disposals take effect.

If we close the T&K BP deal in the summer as we expect, that will then -, in the third quarter and beyond.

But the exact nature of that depends critically on the timing of closure of the T&K BP deal.

So we're working with giving you the three parts, one which is a static part independent of M&A activity.

And then what's going out that we currently have identified and what's coming in.

But all of these deals that have not yet been completed still have subject to them the uncertainty of the actual timing.

And therefore it's hard to get a precise number that it should be somewhere in the range that we just indicated.

And just a follow -- a quick question on your total debt, what does the company have free cash flow and would like to take debt even lower.

Any penalty you can see doing that?

If I heard your question right, is there a penalty associated with driving our debt be even lower than where it is at the end of the first quarter.

No, there's no penalty associated with that.

What we have done as a company as to decide operating with a gearing (ph) band between 25 and 35 percent is the most effective way for us to run this firm.

And therefore it is our view that any time that we drop below that gearing (ph) band we should be doing things to move back in to it.

And in the absence of their being a need for an acquisition which, indeed, there is on this particular occasion, if we found ourselves sitting well below the bottom of the gearing (ph) band for an extended period of time, then clearly the board of directors would have to consider incremental share buybacks.

And that obviously would be something on the mind of this Board.

And should the environment continue to be very robust as we go through the rest of the this year and in to next.

We've gone well over the hour we normally like to limit these conference calls to, but we've got -, a couple of more questions.

Jon Wright (ph) at Citigroup in London.

John, are you there?

Yes, hi.

Can you hear me?

Yes, hi.

I just wondered if I could ask about your gas and power, in particular North American trading profits, if you can give any indication for those?

Well they were higher than they've been in the past.

And this is a consequence of the work that we've done in developing our marketing position in North America.

We were talking earlier about the marketing position that we're continuing to develop in LNG.

We've done in the same thing in the United States.

And through that, I've positioned ourselves to market much more gas than we've produced as an upstream entity.

And so we are out acquiring gas from third parties.

And marketing that to a whole range of customers throughout the countries.

We invested last year in a Kinder Morgan (ph) pipeline, in Texas, and intra state pipeline there, which gave us considerably a more flexibility in responding in to customers requirements.

I think the combination of infrastructure, a large number of customers, and story (ph) has allowed in the first quarter of this year -, that's been very, very volatile with respect to gas prices. -, secure additional margins, a margin that I would hesitate to have you model in to your assumption across the rest of the year.

A better indication of a steady safe position for gas power and renewables should be at the level that was achieved in the third and fourth quarters of last year.

OK.

Thank you.

Let's go to Neill Morton (ph) for Dresdner Kleinwort Wasserstein(ph), are you there Neill?

I am indeed Fergus.

I just wanted to come back to your earlier comment about Slovnoff (ph) could you perhaps give BP's initial view on the Slovnoff (ph) status that T&K has agreed to split with Slovnoff (ph).

And see perhaps if those assets are subsequently forwarded in to the BP T&K, whether BP is likely to face a further cash contribution?

Thank you.

Well we've been very clear on this Neill.

We have a deal to complete with T&K.

So actually with -, involving the T&K -.

That's our primary focus of attention.

Clearly there are discussions taking place about Slovnoff (ph) as well because this is an asset that sits in the outer access renewable portfolio.

And we need to decided between us what we might or might not do with those assets.

So there are discussions that are occurring.

But our focus is on closing the main deal, anything on top of that is additive.

And I could not even begin to speculate at this time what would be a possible outcome.

Watch this space, and we'll advise you if and when progress is made.

OK.

With that we'll draw the -- closed.

And I'd like to thank everybody very much for listening.

The investor relations team in London and New York are always ready to answer your questions.

Any of you haven't had a chance to have their question answered this afternoon, please do get in touch later on today or in the next few days.

And we look forward to speaking you again in three months time.

Thank you very much.