殼牌 (SHEL) 2004 Q1 法說會逐字稿

Good afternoon to listeners in Europe and good morning to those in the US.

Welcome to the Royal Dutch/Shell first quarter 2004 results conference call.

I'm Gerard Paulides, Head of Group Investor Relations in the UK and Ireland, and with me today are Tim Morrison, acting CFO and group controller, and Simon Henry, CFO of Exploration and Production.

Before proceeding

I would like to refer you to our disclaimer about forward-looking statements, which you can find on Page 9 of the quarterly results announcement.

I would also like to draw your attention to some new enhanced disclosures in our financial results released today, dealing with regional breakdown of upstream production data, disclosure of European realized gas prices, and chemical sales volumes.

The results for the group for the first quarter 2004 give effect to the estimated financial impact of the previously announced reserves in categorization, and related to restatement of prior year financial statements contained in the 2002 Form 20-F, as well as a revision of the earnings for 2003, announced from the February 5, 2004.

We remain in discussion with the SEC regarding the financial statements as contained in our 2002 Form 20-F.

Any further adjustments that could arise out of those discussions could impact the quarterly earnings information contained here-in.

Lastly, the publication of the 2003 Annual Report is planned for the May 28, 2004.

As a result, the fourth quarter and full year 2003 group earnings have been adjusted for certain items including the effect of post December 31, 2003 balance sheet events.

I will now hand over to Tim Morrison.

Hello everyone.

Thanks for coming on the call.

We were able to have

, and Malcolm brings it on this morning's press call, which I know some of you were able to listen to.

And I know that the Managing Directors now look forward to having more contacts in the months to come.

This call, as a quarter one call, would normally be handled by our IR department.

But as the new acting CFO here I wanted to join the call to hear your questions and to answer some of them.

And I will, of course, be well assisted by Gerard and by Simon.

Let me start by saying that these results have been delivered by the unstinting efforts of some of 115,000 staff who've worked very hard through what has been, obviously, a very difficult period for us, to deliver energy and petrochemicals to all our customers around the world.

When looking at the numbers, I'll base performance comments on a net income basis but may also refer to current cost of supplies or CCS.

CCS earnings are provided for ease of understanding, although we give equal prominence to net income on a Dutch GAAP and US GAAP basis in formal reporting.

And just to complete that, the group will be adopting International Accounting Standards, as a basis for reporting group and parent company financial statements from January 1, 2005, and I hope this will simplify the presentation of our financial statement somewhat.

I will provide a brief statement of important events and results, and then we'll move into Q&As.

First, we have continued to deliver satisfactory results and cash generation despite all the issues relating to reserves.

Second, we've increased our capital investment in the upstream because of higher costs in some of our major projects.

But we've also switched investment into short-term payback projects in higher margin areas, and we've increased our exploration program for the year.

Third, current strong oil and gas prices enable us to restart the buyback program in 2004, and the parent companies have therefore decided to implement that with immediate effect.

Program, we expect, to be around $2b for the year 2004, and this amount includes the purchase of shares, the hedging of employee share options.

I'd like to provide bit of a context on the issue of buybacks.

Our long-standing dividend policy is unchanged, and the second interim for 2003 will be paid in the second quarter.

Our priority, as we said before, is to invest in long-term sustainable performance, since this is ultimately what sustains a long-term dividend delivery, and we are taking action to restore the competitiveness of EP.

For the year 2004, we expect to invest some $14.5b - $15b, and these figures exclude the minority share contributions for Shakalin spending.

We intend to maintain our gearing within a broad 20% - 30% target band, including operating lease commitments, and if we generate surplus cash that takes away from this range, we will actively consider buybacks against other strategic alternatives.

Shell lost its AAA at a time when credit ratios were improving, and we are committed to maintaining tight financial discipline in everything we do, but we accept that the AAA rating on our debt is gone.

The direct financial impact of this is some 10-20 basis point on group debt and has little earnings impact and to some extent is already priced in.

So, we are comfortable with our gearing level and believe now is the right time to start buyback program.

And our strong cash generation that we have at the moment, means we retain financial flexibility.

If I can now move to some selected group comments concerning the first quarter.

The overall environment has helped our businesses to deliver net income of $4.4b and CCS earnings of $4.3b.

Net income is 16% lower however in the same period in 2003.

First quarter 2003 contained the profits related to the Royal Gas transaction, which we had at the time highlighted as a special, and an adjustment made that quarter for retirement obligations and together these totaled $1.3b.

If we put these items aside into 2003, the earnings in 2004 improved 9% year-on-year.

Reported return on capital employed on a rolling four quarter basis was just over 14% on a net income basis.

Cash flow from operations were over $7.8b helped by decrease in working capital of $1.8b and proceeds from divestments funded the investment program of $3b and supported bond sheet management.

Our gearing, excluding operating leases, reduced to 17.8% ahead of second quarter in which, of course, we paid the second interim dividend for 2003.

Proceeds from divestment totaled $1.7b and included the placement of our holding in Sinopec shares.

This amount excludes the proceeds on the announced sale of our extreme interest in Angola and the refinery in Delaware City.

Our divestments for the remainder of the year will focus more on the down stream business than the upstream.

Capital investment budget for upstream for the full year has increased, this reflects increases due to upward cost pressure in Sakhalin and Bonga and adjustment in the allocation of investment to an increase in exploration expenditure and some short term pay back opportunities.

As we stated, full year group share capital investment is expected to be in the range of $14.5b - $15b.

Just to confirm, this number excludes the minority share of Sakhalin.

Our new business development, we are pleased with the signing of heads of agreement with the Libyan National Oil Corporation for the establishment of a long-term strategic partnership.

This agreement could lead to the development of world-class integrated upstream and L&G export projects.

I will now run briefly through key issues in the main businesses and then we will open the call for Q&A.

In Exploration Production, reported hydrocarbon production was 4.96m barrels of oil of gold equivalent a day and decreased by 1%, if we exclude the effect of divestments of about 98,000 barrels of oil equivalent per day.

With these oil prices, we tend to use an approximate PSC effect to some 10,000 barrels a day for every dollar per barrel movement.

And you need to understand, this is not a very exact number and it's not linear, but the point is higher oil prices may have a depressive effect on reported production but are good for revenue.

Reported oil production volumes were down 3%, gas production down by 4%, so overall reported production down 3%.

Oil production benefited from new production from Athabasca Oil Sands, Bijupira-Salema in Brazil, from Nigeria and from the USA.

In addition, Nigeria recorded higher production from the ramp up of EA field, which is now connected to the offshore gas gathering system.

And we also saw decreased community disturbances.

These were more than offset, though, by divestments in US, UK and Thailand, field declines mainly in the USA and the North Sea, and the down time we saw on Brent production in the UK.

Gas production was down on last year's record production again due to divestments in the USA,UK and Thailand, field declines in the USA and UK, and down time on Brent production.

These were partly offset by new reproduction USA mainly from Nakika.

Turning to Gas and Power, L&G volumes increased by 8%, 2.51m tons as Nigeria L&G Train 3 and Malaysia L&G Tiga Train 2 built up volumes.

This volume is a record for any one first quarter.

Results of portfolio divestments including the sale of Sinopec shares contributed to earnings, $24m relative to a year ago.

Trading performance in UK improved versus fourth quarter of 2003, but was weaker than first quarter of 2003.

In oil products, marketing earnings improved during the quarter in all regions, partly offset by lower refining earnings in primarily Europe.

Outside the USA, high marketing earnings primarily in Asia-Pacific and Latin America, including asset sales were partly offset by lower refining earnings.

Weaker European refining margins increased costs associated with the strengthening Euro and higher refinery maintenance activity contributed to this refining earnings decline.

In the USA, marketing earnings increased due primarily to cost reductions offset by lower retail margins while refining earnings declined.

Stronger refining margins and high refinery intake were offset by heavy maintenance program.

Profit on sale from onshore crude pipeline systems in the USA offset the $93m book loss on the announced sale of the Delaware City Refinery.

Our unplanned downtime in the USA was 6.6%, which is below the average of 2003 of 7.1%.

And the light-heavy differential improved substantially compared to a year ago and also improved relative to the fourth quarter.

In chemicals, overall unit margins improved and sales volume increased by 2% due to stronger demand and increased trading activity.

Earnings more than doubled compared to last year, despite the impact of planned and unplanned downtime and start-up costs for the cracker expansion project at Deer Park in USA.

So, to summarize, we had satisfactory earnings and cash generation from operations of $9.5b, if we include divestments.

Second point, application of cash flow was made due to increased investments to dividend and buybacks.

Business operations continued despite the reserves issues and we are working hard to re-establish the competitiveness of the portfolio.

I'd now like to move to questions and answers and I'll hand over to the operator, who will give you instructions on how to poll for questions.

If any participant who would like to ask a question, please press the star followed by the one on your telephone.

If you wish to cancel this request, please press the star followed by the two.

Your questions will be polled in the order they are received.

There will be a short pause while participants register for questions.

The first question comes from Gordan Gray, please state your full name, company name, followed by your question.

Thanks, this is Gordan Gray of JP Morgan.

I wonder if you can give us a bit more detail on the key variances between the current guidance from CAPEX and the previous $13b figure.

In particular how much is overspend, how much is the raised exploration spend, and how much is on short-term projects?

And then to what extent, the current figure is appropriate going a little bit further forward into '05, '06?

We are spending about an extra $200m on exploration.

There is about $500m on the short-term payback projects.

We had a figure of $13b plus and so, the additional spend elsewhere, you can't exactly add all these up because it was a $13b plus number.

But you can see there, the spend on exploration and additional short-term measures, that will take us to a $14.5 to 15.0b number.

We expect a similar sort of level next year.

Okay, Thanks.

The next question comes from Jonathan Litt.

Please state your full name, company name, followed by your question.

Thank you, it's Jonathan Litt from Citigroup.

Just one question on CAPEX, if I can, the short-term payback element.

I'm wondering how much of that is about taking advantage of the current environment, or how much is about shoring up production?

Is that more of a production decline problem that you had anticipated?

On AAA, given you started the buybacks now, is there going to be an intention to try and get back that AAA rating?

We just simply have some attractive short-term projects, which we will allow us to get a rapid payback and we are reallocating some of our spending to those activities.

At the time of strong prices, it is a sensible thing to do.

Simon Henry here would also like to comment.

$500m on shore payback and that means specifically, we expect these to pay back before the end of next year.

It's not shoring up production.

It's new opportunities around existing infrastructures, primarily in the UK and the US and we are being driven by value and not volume.

There is some offset obviously in the volume against some of the issues on the delay in Bonga, but overall, this is value enhancing at the current oil price.

Yes, just whether you would be attempting to try and get back that AAA rating?

It's obviously painful to lose the AAA.

You are going to do it that often.

We see ourselves now, we have got the AA.

We are not going to chase back to try and get the AAA back in some kind of short order.

We have got a financial framework by which we operate the co.

I think you are familiar with that.

So, we will continue to operate by that, but we are not going to go chasing AAA.

Perhaps in addition to that, John, the question that comes up often is how does it relate to the gearing ratio.

The gearing ratio, we have expressed as a range of 20-30%. 20-30% is typically inclusive of not only the headline gearing, but other commitments as well.

If you take the headline gearing that we reported in this quarter, 17.8%, typically you would add about 7% or so on top of that to get to the number that we are managing, which relates to the 20% to 30%.

Is that a new target because I don't think specifically you said it included operating leases and such before?

What we said in the past is that the range is more than just a headline gearing that has a lot of considerations that come into play, particularly operating leases or other matters.

What has been discussed in the past as well, is how does the pension fund come in or the issue of how do you exactly take operating leases into account, do you take them at face value, do you discount and do you take them before or after tax.

There is many different formulas to get there.

As an approximation, what we are stating to you is that you should add about 7% into the number.

Just one other comment on that which is, I think, we've seen over the last few years a more comprehensive view of obligations from the outside world.

They are looking more widely than they perhaps did a few years ago.

The next question comes from John

.

Please state your full name, company name, followed by your question.

Thanks.

Rising

.

Two questions, one on oil products, can you just give a bit more detail on what's happening in the US?

In particular, can you maybe talk around the split between refining and marketing, maybe indicate the level of unusual costs with the heavy turnaround program you had, and also whether you could indicate whether you are still incurring unusual costs in relation to the rebranding, restructuring, reimaging program that you are putting through?

Could you just walk me through again the math on this increasing CAPEX in the upstream?

I didn't quite get to the $14.5b you were talking to.

Where are you switching costs from to the short-term projects?

Thanks.

John, I'm just trying to count how many questions you asked there to get an orderly response.

I'm going to ask, there are just two with the last one first, which is on the math and the OP question, I can pick, if you want.

Let me first deal with OP question, John.

The progress on the programs in the US deal particularly with three exercises.

One is rebranding of sites and we are now about 75% through that exercise.

Secondly, we are reimaging some of the Shell sites to a new look, which is about 60% -65% complete, and lastly we are taking a look at the optimal size of the network and the location of the sites within that.

We have now removed about 3,600 sites from the network and that would on a total basis would approximate just over half of what we shoot for.

In terms of cost, the second part of your OP question, in unplanned shut downs.

Unplanned shut down percentage in the US is 6.6%.

If you would take Delaware and Bakersfield out of that, it would be 6.1%.

The overall cost impact relative to year ago, inclusive of cost and gross margin, and this is a before tax number in aggregate is for the US is about $100m and for the entire Oil Product corporations including European and Eastern operations that they will fetch $250m and those are before tax numbers.

Let me deal with the EP question now, talk to Sue again, see whether we can get it clear this time.

We've discussed it as well this morning, so it is perhaps a bit confusion around, let me try.

$500m is spent on short-term payback opportunities mainly in higher margin areas, North Sea, USA are examples of that.

There is about $200m allocated to Exploration, that's in 6-7 opportunities, they range from acreage acquisition to drilling to some technology place.

Then there is several hundred forex pressure within the change in the CAPEX number that we have mentioned.

Some of these numbers that I have just mentioned are reallocation of budget, they are not necessarily extra budget, but reallocation of the focus of the investment.

On top of that, we have the project expenditure in Sakhalin and Bonga.

All of that combined, gets you to a new number of $14.5b - $15b excluding the minority Shell Sakhalin and the minority Shell Sakhalin, if I give you the 100% number for Sakhalin in 2004, it is about $3b spending and in 2005 is about $3.5 - $4b, so take 45% of that and you've got the minority share.

Why do we take out the minority share, essentially because we are not the ones funding it.

We will typically show consolidated numbers, but because of the size of the Sakhalin project, we think its a more transparent to present the number excluding the minority share.

I will now hand it back to Tim for dealing with that first question.

Can you remind me of the first question?

Sorry about that, John.

It is fairly clear that refining was good and marketing was bad in the US, so just wondering whether you are heavily over weighing marketing, I was just wondering whether you are able to give some sort of indication of the balance of where earnings were coming from US from your refining and marketing businesses?

The marketing number - out of the $163m you are looking, was $60m, and we had lube $16m, transportation was $108m, and refining was negative $26m.

Well, thats the split, I think, you were looking for.

Thank you.

Operator, can we take the next question?

The next question comes from Michael Mayer.

Please state your full name, company name, followed by your question.

Yes.

Good morning.

This is Mike Mayer from Prudential Securities.

Throughout the press release it mentions a number of non recurring items that previously would have been called special items and it looks like they add up to about $0.14 a share, can you give us a little more color on those items and break them out between USA and world outside the USA, so we could more clearly understand the underlying results?

Thank you.

Mike, you are talking about the impact in Q104 because we referred to special items in Q103 which was the Ruhrgas disposal and the accounting change on asset retirement obligation.

Yes, be a little more clear.

I know you are not calling these things special items any longer and I understand that, but there were some large gains in G&P and E&P and there were some offsetting items in Oil Products.

The biggest single item in these numbers is the gain from the sale of Sinopec shares and because of the way we accounted for the investment, these are spread across EP, OP, and Gas & Power.

So, we had $348m relating to that.

The split between the businesses of the overall, approximately $470m is $228m in EP and there is about $180m odd in Gas & Power (GP), and there is about $80m odd in Oil Products, roughly speaking.

The Gas & Power includes Sinopec and also the sale of the German distribution business.

So, that's all outside the USA.

OP, because we've got the Delaware City writedown plus the sale of the pipeline, they more or less cancel out and then in EP as well as Sinopec, we have got the Thailand sale.

So, I think on a net basis, there is actually very little in the US.

The next question comes from Neil Perry.

Please state your full name, company name, followed by your question.

Hi.

It's Neil Perry from UBS.

On the share buyback, you've estimated a figure of $2b for the year.

Can you tell us -- you must be looking at your own estimates of cash flows for the year when you come up with that figure?

Can you tell us what oil price you are building into your planning assumptions for your management data this year?

Secondly, on volumes, can you be clear on what your volume guidance is at least for this year?

On the share buybacks, you see, we've got a figure of $2b out there, of which part is covered by the option hedging program, which we would expect to be in the range of 700 to 800 this year.

And the rest are straight buybacks.

We have looked at the rate of cash flow so far this year and obviously, we look through to the end of the year.

We don't disclose the basis on which that is done, but we wouldn't have announced this if we didn't think we could see it through.

I'm sure you wouldn't announce it if you didn't think you could see it through, but if you look at the sales that you have announced already so far this year, you are talking about a roundabout figure, $2b of inflows from disposals.

I was just wondering whether oil prices of $34 and high refining margins were going to give us an additional kicker if they stayed out there?

We will see how the year turns out, but we are not relying through our cash cycle on high oil prices right the way through the year.

So, this is a prudent step to take at this place, bearing in mind our desired gearing range.

And as you see, there are cost pressures and we have a high oil price, but we also have a weak dollar, which drives through cost pressures both on spending and operating cost, and indeed increases our dividend outflow.

But fair to say you are using a substantially lower oil price in your planning process than the one we have got at the moment?

For the purposes of planning our cash cycle, we are being conservative.

Simon will handle the volume question.

Thanks Tim.

The volume guidance was flat for this year and down next year as we lose over 100,000 barrels in production-sharing contracts.

An update as we have seen a delay in Bonga, we have seen high prices, great for the bottom line and have an arithmetic impact on our reported production and production-sharing contract areas.

Therefore, there is some downward pressure on the flat guidance that we gave.

However, some of the investments we announced today are expected to offer up to a certain extent.

We are just too early on in the year to give unequivocal guidance.

Probably fair to say that pressures are downwards on that flat guidance.

The delay at Bonga is also potentially having an impact next year.

That again is going to be at least partially offset by the investments we talked about today.

Thank you.

Just to flowchart your question on proceeds as well, Neil, the divestment proceeds indeed for the quarter were $1.7b.

That's on top of the $7.8b cash flow from operations.

Not included in these numbers are the intended sales announced for Delaware and Angola in terms of proceeds.

Can we take the next question please?

The next question comes from Fred Leuffer, please state your full name, company name, followed by your question.

It's Fred Leuffer from Bear Stearns.

Are there changes -- any other changes in CAPEX or business segments outside of E&P?

What do you expect the impact from the short-term projects to be on production for this year and next?

And can you provide us an EPS on a diluted basis, please?

On the first question, the only very change in CAPEX outside the EP division is Gas & Power share of Sakhalin because the project is split between EP and Gas & Power.

In terms of production this year, it depends on exactly how quickly we bring these projects online, maybe 10,000-20,000 barrels a day this year on average, maybe double that again next year.

And the last question on EPS, Fred, I will take that after the call and I'll give you a call on that

separately.

Thank you.

Can we take the next question please?

The next question comes from Irene Himona, please state your full name, company name followed by your question.

Good afternoon, it's Irene Himona at Morgan Stanley.

I have two questions, firstly on the increased capital expenditure this year, for your CAPEX to rise to the $15b level you indicate, you need a very substantial step-up in the quarterly run rate, 35% to 40%, perhaps.

Are you actually going to spend that amount, do you think?

And my second question, well it's from a previous question by Neil on the financial framework, the 2003 absence of a share buyback was explained by the need to be cash flow neutral at $20.

Can we infer from today's restart of the buyback that you are actually cash flow neutral or are you raising the

?

On the CAPEX, I mean obviously it's saying people will need to work hard on to spend the money.

I would just point out, we tend to have a low CAPEX particularly in OP in the first quarter.

So, the first quarter run rate isn't particularly indicative of the year.

We will be monitoring as we go through.

On the financial framework, we have concluded when we are looking at the how we dispose off the cash generated this year, particularly after a very strong quarter, there are funds available to start a buyback program.

But it's essentially that the cash is available and we look at how we should dispose it.

Given where our gearing is, we think it's sensible to return some of that capital to shareholders.

Okay, thank you.

We'll move to the next question operator?

The next question comes from JJ Traynor, please state your full name, company name followed by your question.

Hello, it's JJ Traynor from Deutsche Bank.

A couple of questions please, the project management issues around Bonga and Sakh II, there have been some quite material delays to Bonga and I think cost overruns to both.

Could we get some more details on what's actually happened there and what you are doing to fix those issues, I guess, on future projects?

Secondly, the upstream margins outside the United States were down quite surprisingly.

I wondered if you could you talk about some of the movements in there?

And finally, it's actually that you haven't had an awful lot of time to assimilate this new CAPEX estimate.

People are in their new jobs.

How much confidence that you have got for 2004 in the guidance that you have to 2005?

Simon, do you want to take the project management question?

Thanks JJ, Bonga and Sakhalin are both in quiet different stages of development.

Bonga FPSO units are now on station.

We are in the earlier stages of booking and the flow lines completing the topside.

Several project management issues over the life time of the project ranging from a original contracting approach through the performance of contractors in the UK and fitting at the upsides and the level of productivity is achieved, and we have been through a recent project review, and I can tell you in time I'd been on the street that 15% of my time has being spent on this project management issues, and that way, I think we are petty confident given what we have in place now that we can deliver the project on time, and on the latest schedule on the latest budget.

It is relatively significant increase but the upsides which found a bit more reserves are feebler reserves while within the process.

The sub surface which has over all done very well, just basically been contracting on the FPSO and the subsequent flow line hookup.

Sakhalin much different stage of development, we are late 2000, first LNG so we are still three and a half years.

We have been through seven or eight months since the original investment decisions was taken.

We have had a review of the project in terms of the management of the project from the island and the contract performance we have several upward cost pressures form exchange rates in the way they have move from the materials such as steel and cement and the tightness of the contract marketed in the Far East.

So there is a lot of generic factors and on top of which, which is a huge ten plus billion project.

Very large, rely very complex and in its in the frontier area.

We are in back that over that period.

We are not necessarily happy with what we have learned, we have been through the significant review of again the management structure and a lot more confident in what we can do on that project going forward.

I can tell you Malcolm has been quiet some significant amount of his time on that.

Probable just a cover of the CAPEX growing forward they have confident they are at least any EP that there weren't more to come, and I am sure Tim will pick it up from the brief perspective.

On the projects I talked about, I'm

on the large project.

We have been going through the reviews that I talked about.

There are always other options available but they will only be considered in the lights of available cash, affordability and the return available then.

Let me just comment on the other businesses, clearly the area we have had, the biggest challenge which has been the major complex projects in EP, and we are confident that the numbers we have got near the businesses and the numbers we will get to, and the capital discipline program.

We essentially say to the businesses, this is the capital we have got and then come back for more.

But I recognize and thank you for your acknowledgement that we have not had that much time to simulate.

Okay.

Hey JJ, on your comment on upstream margin, is that the earnings to barrel?

Earnings barrel of 1Q to 1Q outside the US.

But it's the unit margin a barrel or the earnings a barrel you are looking at, not at realized prices.

The unit margin, the earnings per barrel?

Basically the divestment of being the US and UK relatively high margin and some of the new production and Nigeria and Canada was relatively lower margin.

Thanks very much.

The next question comes from Mark Iannotti, please state your full name, company name followed by your question.

I am Mark Iannotti from Merrill Lynch, Tim.

A coupe of questions, first of all US downstream, you have indicated unplanned downtime falling to 6.3% in the quarter from 7.1%.

Would you as a disappointment, given that, some half disposed was performing refinery.

And can you just talk about the progress you are making towards getting to your 4% target for the year.

And secondly, in the previous discussions we had over the years and the meetings on Sakhalin the company has been at pains to stress that the benefits are real intangible and more than just prestige.

Can you just make some comments on where you think you've lost some business or some competitive position as the ratings gone?

Well, I'll if I can just dare with your second question first Mark.

The rating has only very recently gone and we hope that the impact will not be as great as we might have feared.

I think from the comments, when rating agencies recognize that financial strength is not really the issue here, they recognize we are very strong financially, but obviously following the reserves issue, there is some concerns around management and governance and of course, we are working hard to put all that right and that it remains to be seen.

Of course, we do also notice that some of our major competitors seem to thrive without AAA.

So, we will aim to be in that same happy state.

And just on the downstream and downtime, you mentioned I think 6.3%.

It was 6.6% including Delaware, 6% without.

This represents the continuation of a trend since 2001 where we are continuously getting that number down.

So, we are still targeting the 4% and we are confident we can achieve it through a number of changes, improving management, and so on.

Okay, Thank you.

We'll take the next question, please.

The next question comes from Neil McMahon.

Please state your full name, company name followed by your question?

Hello, its Neil McMahon from Sanford Bernstein.

Just a few questions, one is really on European volumes both gas and oil, there has obviously been some divestments in there, but they are still quite low.

I wonder if you could go through both splitting out onshore and offshore?

In particular, looking at the UK, North Sea, and Groningen, what is the underlying decline rates there and what is the uptime on average of the deals?

Then secondly, on Angola, it would be good to get a reasonable explanation of why you decided to get out, given the fact that future volume growth is going to be paramount for the company?

We have heard rumors about problems with government relations, but also might the discoveries that were part of your portfolio maybe not have been as big as you would have anticipated?

Thanks.

On the first question, Gerard whether we - those are pretty detailed questions you have there.

The guidance for decline rates, in general to start off with, we don't entertain questions on individual fields, typically unless there is a very good reason to talk about that particular field.

We have spoken about Brutus in the past.

The general guidance for the company is 6-8% decline rate, bearing in mind that that is partly influenced by what is happening in 2005 with the PSC contract that we have mentioned before where we would lose about 100,000 barrels per day in 2005.

So, that influences the 6-8% range to an extent in terms of the consideration for Angola, and then back to Tim.

The issue in Angola is we simply don't really have critical mass.

We don't have other assets that we can leverage with cross-business synergies etc.

So, that's the heart of the issue.

We can use the capital better elsewhere.

It will be also good to get a comment on the uptime in the North Sea.

I know you are not going to talk about decline rates, but overall in the North Sea, what would your uptime have been recently?

Let me just make one remark on uptime on the one that probably attracts most attention, which is the Brent field.

The Brent field came back up during the quarter.

I think gas production is pretty much where it was before.

Oil production still has a bit of way.

All in all, the impact for the quarter was in absolute terms about 40,000 barrels a day that includes effectively the late start during the quarter of the Brent Charlie platform and the Penguins field feeding into that.

To compare that number, in Q4 of 2003, the impact of the Brent downtime was 70,000 barrels a day.

So, in a comparative fashion, you are picking up, what's it, 30,000 to 40,000 and you still have a bit to go for the next quarter.

The next question from Al Anton.

Please state your full name, company name, followed by your question.

Abert J. Anton if you wanted the full name.

Carl Pforzheimer & Co in New York.

First I would like to wish all three of you well on your new assignments especially, Simon Henry who went from the frying pan of dealing with the analysts to the fire of this very interesting area in the upstream.

My question is on the reserve downgrading, I wonder if you are -- you have said that after adjustments, you have replaced 60% or so of reserves over the last five years.

I wonder if you will publish a detailed recap of that year-by-year, maybe in the Annual Report so we can get a good feel of what the situation actually was?

And secondly, with the possible restatement, upgrading of reserves, and the number of new projects that you have, how confident are you of replacing 100% or more in the immediate years ahead?

I will deal with your first question.

We will be restating our Form 20-F for 2002, which will show the reserves tables, 2000, 2001, and 2002, and then of course, we will be publishing also the 2003 numbers.

So, that will give you a picture of where the changes are at least in the last few years.

In terms of future confidence, we will be saying over the next five years, roughly half of the reserves that have been recatogorized coming back in as proved reserves.

So, that gives us something of a boost.

We've said we expect to average over 100% over that period.

That's not necessarily every year, but on average over that period.

We hope to do more.

We do have some good large projects still in progress with limited number of reserves, booked none in some cases such as Kashagan, Qatar,

and Sakhalin and we hope to see projects like

moving forward as well.

So, hope to do more.

The next question comes from Jeremy Elden.

Please state your full name, company name followed by your question.

Good afternoon.

This is Jeremy Elden from Lehman Brothers.

Could you just give me some small points, firstly the impact of IAS accounting?

Do you expect it to be too material and will it give a divergence between the group figures on IAS and on US GAAP?

And secondly, on Sakhalin financing, I take it from what you've said about the minorities financing their share and also I think, I can see it in the cash flow statement, are they paying out quarter-by-quarter more or less their share of a CAPEX as a subscription of new equity to the Sakhalin Co. or is the Sakhalin Co. actually having to go out and borrow money in the market?

And finally, on the shares in issue question, you seemed to have sneaked that reduction in shares in issue through and no one was looking at the fourth quarter figures.

It would be very handy if you could, on a quarterly basis, give the diluted EPS and shares in issue?

Jeremy, Tim here.

Just dealing with your first question on the impact of International Accounting Standards, we are still in the process of looking at the impact.

We've had a program running for some time on this.

As we've said, we will be accounting on IAS from January 1, 2005 and that will be sole IAS.

So, we will not be accounting as it were hybrid that covers both IAS and US GAAP.

So, that means we will be reconciling when we file our Form 20-F.

In terms of the impact, there are, of course a number of decisions and choices to be made when first time applying IAS and we are still looking at those.

Those will get swept off into the opening balance sheet.

There will be some differences coming through, but we are not in a position yet to estimate how they will work through partly because the analysis is going on and partly because some of these choices haven't yet been made.

Alright, Thanks.

I think this is something, we will have a much clearer fix on - we have to have a much clearer fix on towards the end of the year.

On Sakhalin, Jeremy, like most joint ventures, the partners are all contributing their share of the cash goals on a proportionate basis, monthly, as and when required in terms of the project.

The project is simultaneously seeking project financing through JBIC.

Ultimately how that is structured remains to be seen, but that was always the intent, and the amount of coverage from the project financing is still obviously under negotiation.

Likely to mature over the next 12 months or so and driven in part by the sales contracts in place and the revised budget, as and when that is confirmed.

Right, so the $277m change in minority interest in the first quarter, that's essentially the partners paying out from the cash goals there, is it?

That's correct.

Right, thanks.

On the shares in issue point, I assume you are referring to our exclusion of the shares held to back options.

This was actually something that the SEC pointed out, so in fact we have to increase our earnings per share as a result of this.

I don't have the fourth quarter earnings release with me.

But I thought we had showed it fairly clearly at that point.

But I wouldn't swear to it.

No, you did.

But funnily enough, on the fourth quarter earnings, we were all focused on something else.

I see.

So, we.

It would just be handy if you could show a diluted EPS number quarterly as I think most others do?

Because, obviously that's going to be 2% - 3% lower than your new EPS number.

There is no problem in providing any numbers about that, and as I said earlier during the call, I will provide that number after the call, Jeremy.

Indeed, it was covered extensively, I saw it as well in fourth quarter, but let's deal with it after the call and we will make sure that everyone who's interested gets that number to them.

Beleive me, we will not try to distract you from this.

No, that's why you had the reserves this year, to distract us from that.

Thanks.

Next question please.

The next question comes from Allard de Buijzer, please state your full name, company name followed by your question.

Good Afternoon, this is Allard de Buijzer from Fortis Bank in Amsterdam

Allard, could you speak up?

Can you hear me better now?

That's alright.

Ok, few questions first of all Exploration, you told us that exploration will go up this year, but in first quarter, the Exploration costs were about half those of last year, down to fairly low of $116m.

Was that due to a late start in drilling or were you extremely successful in your exploration program this time?

Part of the effect is because the - I will ask Simon to come in if he can add something bit, part of the reason for the low level was because some of our costs went back into 2003 because we've still got our books open.

I think we have pointed out that there is a minor net effect on the 2003 numbers because you get some adjusting events that happen before you close your books and some of them need actually to be booked back into the 2003 numbers.

Now, the net effect of that is actually negligible, but part of it included some exploration write-off.

There maybe some more to add to this.

In the quarter, we had a relatively low seismic activity with about 56% success rate, if I recall correctly.

I also draw the attention to this restrained exploration expenditure, the total and what gets expensed in the quarter.

We took back $200m extra today, that's on top of a budget for the year of $1.2b.

So, the total expenditure, not all of which will be expensed, is now $1.4b, about half of that is usually spent on drilling and successful wells are not necessarily expensed.

Obviously, they are capitalized until through appraisal.

Ok, next question, Chemicals that you now provide volumes, thank you for that, if I make a calculation, then the prices, the average unit prices must have increased by something like 66%.

Is this a usual way at looking at these developments or what are substantial changes in the product mix or that is useless to look at it?

Can you explain the price change?

I think there has been a modest increase in prices, but there must be something wrong in the calculation you are doing.

I would rather take that offline.

We should get back to you.

I suspect part of it is the way that the feedstock prices are playing into the numbers you are using with.

If you allow us, we will take that offline.

I've just divided the sales figure you've provided by the volumes.

I think it's very dependent on feedstock flowing straight through.

I'll cut you off here because we have got many people on the line.

I've one further question, if I may?

Sorry, I will move on to the next question.

You had two questions.

I do apologize, but I would like to move on.

Next question please.

The next question comes from Maria Lomas.

Please state your full name, company name, followed by your question.

Hello.

It is Maria Lomas from Putnam Investments in London.

I just have a further question on your rating, I got your comment that you don't plan to chase back the AAA rating, but I am sure you are aware that you are still under review for further downgrade by the rating agencies.

How confident are you that you are right now at the bottom and you are not going to see further downgrades?

Also related to these, are you confident that your short-term rating for the commercial paper is going to stay where it is right now or could you expect a downgrade on that?

Thank you.

To be clear, I mean, we operate by our financial framework, which is a prudent conservative one.

It's obviously up to the rating agencies to decide whether they would choose to make any further adjustments.

As you correctly pointed out on credit works on the long-term rating, there is no issue at all with our short-term ratings, which is not a surprise given our financial strength.

Okay, thanks.

May we have the next question please, Operator?

The next question comes from Colin Smith.

Please state your full name, company name, followed by your question.

Afternoon, gentlemen, it is Colin Smith, Credit Suisse First Boston.

Two questions, typical two questions.

Just on the new $200m of exploration expense, could you tell us where that is going and also, why it's being added to the budget?

Is that to do with prospect maturation changes in your oil price assumptions or anything else that might have affected that?

And also, could you just - I think Simon, you mentioned that the short-term payback portraits worked at current oil prices.

That obviously seems pretty aggressive when the pricing is at $34 a barrel.

Could you tell us a bit more about the assumptions underlying the decisions to spend the extra $500m there?

Thanks Colin. $200m in six or seven different areas, some of it is license acquisition, some of it is well seismic, and there is one piece of technology acquisition.

It includes

Nigeria where we have had recent success, offshore Brazil, some in the Far East, and at least one opportunity in North America.

Why are we doing it?

It's not for short-term payback on the exploration.

This is long-term; therefore, there is no change in underlying pricing assumptions behind what we spend in exploration because this is very much a long-term return play.

We are doing it because we believe there are opportunities there that will add value to the portfolio.

It is essentially putting more opportunity then at the front end of the funnel.

I did mention current oil prices, more accurately would be prices above our normal planning premise, but they are certainly not today's forward curve.

Can you put a number on that, a rough guidance?

What I can tell you is on an MPV basis, these things will fly at less than $20.

In fact, they are fairly very attractive at anything above $20.

Thanks very much.

Operator, next question, please.

The next question comes from Angus McPhail.

Please state your full name, company name, followed by your question.

Yes.

Hi gentlemen, Angus McPhail from ING.

Just two questions, if I may.

Could you possibly update us as to what level of cost and synergies you've realized to date from the acquisitions that you've done, and in particular at all on Motiva?

Given the fact that you've highlighted today the cost pressures upstream, do you actually intend to revise your cost and synergies target from the absence of any analyst presentation?

Secondly, I hate to bring this up, but could you quantify the litigation and legal costs, which you may have experienced in 1Q04 and perhaps give us some guidance as to what provisions you are setting aside for that going forward?

Angus, thank you.

We said at the end of last year, we wouldn't be reporting synergies, again having completed a bulk of the work there.

We are continuing to drive underlying unit cost improvements and that excludes the impact to exchange rates.

So, it can be quite difficult to match that to our headline costs.

By and large, we see ourselves and this is - different businesses actually have different experiences, but by and large, we see ourselves still on track at the moment.

So, I won't go into more detail than that.

If I can deal with your third question next, then I am going to ask Simon to talk about the cost pressures in the upstream.

On litigation and legal, it's simply not possible to estimate what if any costs might arise from either private litigation or regulatory act in relation to the reserves issue.

It's obviously something we are monitoring, but too many uncertainties and we are obviously booking legal costs as they are incurred.

The cost in the first quarter was something not material in group terms.

Although we have had quite a lot of

helping this obviously and won't be material in group terms for the full year on our current outlook.

But of course, I was actually very cautious about that because it really does depend on how these issues unfold over the coming months.

Okay, thank you.

Simon, do you want to deal with the next question?

Angus, were you actually asking about the upstream cost pressures or are we just acknowledging it and asking about synergies?

Yes, I was actually asking if the fact that your costs have gone upstream, does that mean that you necessarily have revised cost targets?

In other words, do you have revised F&D targets which you are using internally, which you might be amenable to disclose externally in the absence of any analyst presentation?

So, it's the capital cost rather than the operating cost.

We don't actually plan the business around an F&D cost, Angus.

So, we'd probably had this discussion before, but F&D cost is primarily a function of your portfolio.

If we look at Qatar or Sakhalin, Kashagan, and Athabasca, 6b barrels of potential reserve there.

They have got hugely different F&D costs.

So, it would be ridiculous for us to look across the whole portfolio and target a particular F&D cost.

You have to look at each project on its merits and the revenue stream that's associated with it.

The projects that I have just mentioned, the F&D costs you will see in our accounts will vary from less than a dollar or above to quite a significantly higher number.

It's not something we drive our business on.

Obviously, for the projects that we talk about have increased the F&D cost there, but both of them still look attractive economically going forward.

I would say we are about the time we get to September, I think we would like to be able to give a bit more clarity on this.

Okay, thank you.

We'll take the next question, operator?

The next question comes from Bruce Lanni, please state your full name, company name followed by your question.

Hello gentlemen, Bruce Lanni, AG Edwards.

I've two questions related to the upstream, hopefully you can provide some clarity on.

First Malaysia, and then you have got a fairly major discovery out in that region.

Is there any way that you could provide us or quantify what the reserve potential is, even if it's based on pre-drill estimates?

What would you be looking at for development options, timing, and costs?

And then a second question on Libya, obviously, you've announced you are in discussions with the government.

I was just wondering what stage you are in your negotiations with the government or discussions?

And is this an area that you would go soloing or would you be looking for a partner?

And the third element of that question would be what do you favor in Libya?

Do you favor purely an integrated project or LNG, as you've cited both in your comments in the past?

Can we talk on Libya?

Yes.

This is very early days because I think we've got the agreement with the Libyan National Oil Company.

This is the recent signing and we will see how that develops, but we are looking at a variety of possible options there.

Just to be clear, Bruce, some of today's increasing exploration budget is allocated to Libya just following up the discussions we have been having and that will help scope out and answer some of the questions you pose.

On the Malaysian question, it really is too early to give any volume estimates, but this is a significant discovery.

Is there at least some way you can quantify?

Obviously, you know, when you entered into these prospects, you must have had a pre-drill estimate or at least a range you were looking at?

Let me give you some guidance.

We talk in terms of drilling, particularly our renewed focus on the bigger opportunities.

We talk about Big-Cat wells; definition for us is greater than 100m barrel, 100% prospect.

The Malaysia discovery was in that category.

There were several discoveries in the area, not necessarily all Shell's in the way actually get development and then be subject to quite some appraisal work and potentially discussing with partners over a period of time, but it was a good start to the year.

And in fact just revert back to Libya, please, I mean one other questions I asked if it would be an area that you would do a 100% or is this something that projects would be so large that you would be seeking partners on?

We already have the Libyan Co. You are talking about?

Western Oil companies outside of Libya, yes.

No, it's too early really to say on this.

The next question comes from Eric Manting.

Please state your full name, company name, followed by your question.

Good afternoon.

It's Eric Manting of Rabo Securities in Amsterdam.

I was wondering whether you could specify how you realized your $1.8b reduction in working capital and what the number should be for the year?

I think that's for the year.

It's very hard to predict.

It depends on a number of factors.

The reduction that you see this quarter is in net terms, essentially driven by changes in tax with particularly fuel tax and timing of demand and timing of payments.

Great, thanks.

Okay.

I think we will conclude the call for today.

Thank you all for tuning in and listening.

We much appreciate the time you spent with us today and meet you next time.

Thank you.