殼牌 (SHEL) 2002 Q3 法說會逐字稿

Good afternoon to everybody in the U.K. and Europe, and good morning to everybody in the U.S.

I'm Simon Henry out of Royal Dutch Shell Industrial Relations.

I'll give you a short summary of the results today then open the discussion to questions and answers but first could I mention a diary event.

We've moved our normal December strategy presentation to February the 6th next year and we'll repeat it in the U.S. on the 7th.

I love the investor feedback but the late December dates where the meeting had traditionally settled, was too close to the holiday season to get an effective analysis and reaction.

We responded to this audience view and look forward to seeing our listeners in person on the new date.

This quarter, the group reported adjusted CCS earnings of $2.24 billion compared to $2.6 billion a year ago.

Much lower refining margins more than offset higher group prices and the earnings also included one off $300 million impact in the change in U.K. taxation.

Reported net income of $2.64 billion rose 7% from last year.

But I think I've included benefits of the continued portfolio upgrading, as we sold a number of noncore assets.

These included a small interest in Hein gas in Germany and half of our 50% share in Brunei Shell Tankers, leaving us with a share in that operation which matches our share of the associated LNG plant.

We also benefited from the sale [Bioproducts] and the pipeline in the United States.

Our total proceeds from disposals this year are now $.8 billion, that excludes the sale by [INAUDIBLE] earlier this year of the [TAKEHOUSE] pipeline system for some $750 million and the pending disposal of our interest in rural gas.

The cash generated from operations is very strong this quarter, from $5.6 billion bringing the year to date figure to around $12 billion.

The ability to generate significant cash is an important pilar of our overall financial framework, it enables to us deliver on our dividend policy and to buy back shares.

It enables us to reinvest substantial sums in the business in a sustainable way, including the long term world-scale projects that will deliver value for many years ahead.

In the third quarter, we bought back a further $.7 billion of shares bringing the total for the year to around $1.3 billion.

Return on capital employees for the last 12 months was 12%.

During that period, we've seen conditions that is roughly equate to reference conditions, in particular the weak refining margins that provide an offset to the strong oil price.

The normalized [INAUDIBLE] for the group was also around 12%.

Capital employed was around $87 billion at the end of the quarter, in part reflecting a high level of cash over the quarter end when we had $2 billion available temporarily to pay for the Pennzoil acquisition.

Capital employed also reflects our recent deals in which we're beginning to capture the finishes we planned for.

This plus the one off tax impact reduced returns to below our target levels.

We continue to make progress on unit cost reductions in all of our businesses, while we don't report fully each quarter on this activity, I can give an update on the constituent parts of the business.

BP is making good progress despite additional costs incurred as a result of the Gulf of Mexico hurricanes, and some increases in service company rates.

Whole products marketing is back on track to deliver and this is the biggest single contributor to the overall group target.

Oil products manufacturing unit cost have suffered from low volumes, partly elected cut backs in Europe and Asia and partly some unplanned shutdown effects.

Two fall shutdowns in October have already negatively impacted the potential here compared with the 2% reduction mentioned recently in the Houston presentations.

Actual effects of the shutdowns have still to become confirmed.

Chemicals is on tract to deliver its unit cost target and it could overdeliver, even recognizing that we will incur additional project and turnaround costs with lower manufacturing volumes in the fourth quarter.

This continued progress on cost is independent, of course, of the normal seasonality on costs, where it's reasonable to expect an increase in the absolute level in the fourth quarter.

The four major strategic fields that we've completed this year are together very significant, totaling $10 billion of equity and assumption of around $6 billion of debt.

Together they offer significance in opportunities for performance improvement, creating value for the new shareholders.

Integration and synergy capture is going well in all of them in line with plans in each case.

In the German downstream, improvements now running at an annualized rate of $60 million up from the $40 million at the end of the second quarter.

Following the early completion of the acquisition of RWE's interest in the JV, we now got 100% of these benefits.

The progress also made in reinstructing the retail network in Germany, divestments covering the required 2 million tons of volume reduction, are being negotiated.

Some 50% of these have been or will become completed in the coming months.

In the U.S., site rationalization rebounding is also proceeding a pace, by the end of the year, we expect to have rebounded some in 800 sites, 30% reduction in overall site numbers is expected now with only a limited impact on our leading market share.

Also in the U.S. the Pennzoil acquisition was completed on the 1 of October, just after the end of the quarter.

We've already identified seven blendings and distribution plants for closure, which will deliver the first traunch of the expected $140 million of synergies.

The Enterprise acquisition and integration, is proceeding very rapidly with the London, Houston, Aberdeen and [INAUDIBLE] offices all now closed.

And 272 staff have left or will leave by February next year.

The Enterprise assets are now integrated into Shell operating units, and we're applying Shell technology and processes to them.

We remain well on track to deliver our synergy targets.

In addition to the major deals, we continue to make steady positive progress on our major organic investment opportunities.

We have a very pleasing record in exploration this year to date, 66% drilling success rate, a string of discoveries hovering around 800 million barrels of oil equivalent to overall resources.We've continued to develop the major upstream projects in the Gulf of Mexico, Nigeria and Canada, and new LNG capacities nearing completion in Nigeria and Malaysia.

Currently in the process of integrating the newly acquired assets into our global investment ranking program, a process that will deliver further synergies just as we announced at the time of the Enterprise acquisition.

Particular recent highlight has been the progress on the of Nan Hi chemicals project in Quangdo Province China.

The past two years, we've developed partnerships with both CMOC and Sinopec for significant business opportunities in China for all our business streams.

The cash development project, including the West East Pipeline in and Nan Hi the two most prominent of these.

They're complemented by the existing upstream offshore production.

The retail joint venture in Jangsu Province, the LNG supply contract for Quangdo and the coal gasification plants.

Together these activities represent the foundations of a major integrated long-term presence in a very significant country in the global energy market.

Moving now to the businesses.

Exploration and production earnings of $1.68 billion, were 5% below a year ago.

The low hydrocarbon realizations were higher overall, and volumes were up overall 9%, including Enterprise and 2% on an underlying basis.

Several other effects provided an offset.

Notably, as expected this quarter, we included for the first time, the effects of the change in the fiscal regime in the U.K..

Because we couldn't reflect the higher tax rate last quarter under the U.S.

GAAP, this quarter included a catch up for Q2 and the impact of the tax change on deferred tax balances.

These amounted to some $300 million.

Additionally, there was the ongoing effect of the 10% high U.K. tax.

This equates to some $50 million a quarter at the current oil prices and exchange rates.

We also have higher depression in the upstream, up by some $490 a year ago.

Higher end $175 million from the second quarter.

Some of this cost was related to the higher production, particularly in the U.S. and Russia, but it also reflect the depreciation associated with Enterprise including the amortization for purchase price premise.

The Enterprise depreciation was some $280 million this quarter, slightly higher than Q2 as we've now firmed up the depreciation approach to the full purchase value of the acquisition in line with our normal conservative accounting practices.

Premium amortization now amounts to about $80 million after tax.

Some of the acquisition premiums have been allocated to assets in the U.S., this is resulted in higher depreciation in the U.S., that might otherwise have been expected.

Volumes were higher this quarter, as Enterprise produced some 230,000-barrels of oil equivalent to date, 10,000 below the figure for the second quarter, due to normal U.K. offshore maintenance routines.

Excluding this contribution, volumes were 2% higher than a year ago.

The U.S. was a major contributor to this growth with 15% oil growth and 12% gas growth.

Extra strength excellent underlying performance across the asset base in the U.S.

This included the [INAUDIBLE] field which came back on stream, produced some 88,000-barrels of oil equivalent today over the quarter.

Elsewhere, gas productions support record third quarter LNG volumes also contributed to the increase.

We did suffer reduced production in the Gulf of Mexico as a result of the hurricane activity and this will be reflected in both Q3 and Q4, in total, just over 7 million-barrels.

Taking into account all these factors, we're still confident that we will achieve our target for this year of 3.8 million barrels of oil equivalent per day, this of course excludes the volume for Enterprise.

It was also stated at the $16 reference commission.

While we continue to make progress on our underlying unit, BP costs, there are number of other factors that affected our total costs.

The weakening of the dollar particuarily affected the translation of dollars to cost in Europe, in the U.S., while hurricanes didn't knock us off on volumes, we did incur additional costs for facility evacuation and remedial activity and of course much of our operating cost remained despite the production shut-ins.

We also had additional cost-related to the early stages of growth projects such as [SACOLIN].

Our ongoing tax management program provided a contribution of some $120 million this quarter, from several countries outside of the U.S. and EP, and there was a partial offset to this in the corporate sector.

Turning now to gas and power.

Gas and power earnings were up $127 million, this is down from the $300 million a year ago when the results included a bonus of about $75 million for the performance of the NGL natural gas liquid assets transferred into Enterprise LLP in the United States.

This is not the same Enterprise that we purchased earlier this year.

LNG continued to perform well as a business with record third quarter volumes 4% ahead of a year ago.

In particular, we're able to take advantage of significant short-term sales opportunity to sell into the Atlantic basin.

Q4 volumes are traditionally strong and growth in LNG sales should continue in 2003 as new plants come on stream.

In particular, the third train in Nigeria should start ramping up from the start of 2003 and the Malaysia Tiga plant should begin in the middle of next year.

In the longer term,. a further step forward was taken this quarter with the Northwest Shelf in Australia winning the tender for LNG supply to Quangdon gas terminal in China.

LNG unit margins were down a little from a year ago, reflecting both the higher short-term sales and the usual time like linkage to oil prices that's around six to nine months.

This effect should ensure an improvement to marginsQ4.

Dividends from LNG activities in Malaysia are reflected directly in the earnings and due mainly to phasing were lower this quarter than a year ago.

They're expected to be a similar level in Q4 as they were this current quarter. [INAUDIBLE] and trading and power results continue to be weak, reflecting the difficult environment, particularly in the U.S.

In oil products, earnings bounced back somewhat from $347 million in the second quarter.

At $527 million this quarter, they're still way below the $799 million a year ago.

This reflected the continuing weak refining margins and slightly weaker marketing margins.

There's a particular benefit in the U.S. this quarter, resulting from a permanent stock reduction as trading activities and Equiva were integrated into Shell global trading operations.

The U.S. had accounted on a lifo basis and a sub-position was built on prices that reflected year-end 2001.

As this stock was liquidated, gains on the stock were realized, and this was worth some $50 million after tax.

Excluding this effect, the U.S. results would have been positive but not strongly so.

Again, a reflection of the very weak refining environment, and as in Q2, the U.S. gulf coast coking margins were additionally impacted by the low light to heavy crude price differential.

Outside the U.S., marketing margins were 30 to 40 cents a barrel lower than Q3 last year, although slightly better than Q2.

On a year on year basis, declines were seen in the U.K., Malaysia, Argentina, Brazil and South Africa.

While margins in Argentina are down from a year ago, the situation has stabilized a bit now and we are now able to focus more clearly on the prospects for our business there.

We're undertaking a strategic review of our downstream activities in the country and expect sales to comment on this in our Q4 meeting.

This could result in a change to the carrying value of the Argentian assets.

Excluding the U.S. and Germany, where the recent deals make direct comparison difficult, sales volumes held up very well against a difficult economic environment.

Global businesses continued to make important contributions to earnings at similar levels to both Q3 last year and Q2 this year.

There's a much lower level of refinery shutdowns in Q3, compared to the high level seen in Q2, especially outside the U.S.

A somewhat higher level of shutdowns will be reflected in the Q4 results, particularly in the U.S. where there was an extended shutdown, as well as shutdowns at Martinez, L.A.

Deer Park, Delaware City, Port Arthur and North Oak.

This includes unplanned shutdowns at four refineries, all on the Gulf coast as a direct consequence of the hurricanes that were in October, outside the U.S., refinery turn arounds are expected to be at normal levels in the fourth quarter.

Freighting and shipping results continued to be fairly weak, the former due to the limited opportunities, and the latter because of the weak trade rates.

Chemicals continued this upward trend, but overall, there's not been any significant uplift in the environment since the second quarter, some of our businesses performed particularly strongly with record earnings in styrene monomer, proclean oxide, which benefited from capacity addition in Singapore and improved margins.

Polyolfins business managed by Shell was significantly improved on a year ago, reflecting unit margin recovery and benefits from synergies, but were overall slightly weaker than in the second quarter.

Results in lower olefins business improved on a years ago but were nevertheless fairly weak.

Reflecting to some extent the continuous in the U.S., the unfavorable economics of liquid cracking as the oil prices remain steadfastly high relative to gas.

A particular feature of the quarter was the 8% volume increase from a year ago, reflecting additional capacity in the U.S. and in Singapore.

Nevertheless, operating rates remain low both for the industry and Shell, and the continuation of the upward performance trend is far from certain.

In particular, the fourth quarter often brings lower seasonal demand in manufacturing activity.

Other industry segments contains the activities of both our new growth businesses and our internal computing provider.

Timing and IT cost recoveries from other businesses, and the segment shows a small profit this quarter.

Excluding this effect, there was an improved underlying performance coming particularly from Shell consumer.

Looking forward, losses of about $40 million or so expected for the next few quarters in this segment.

However, in the fourth quarter, timing of further IT cost recovery should offset those to some extent.

This figure is lower than previously advised reflecting the rationalization of the portfolio undertaken in the second quarter this year.

The corporate segment included two notable effects.

Higher interest expense resulting from higher net borrowing, related to the Enterprise acquisition, cost around $50 million, there was also a one-off charge included in the interest line, charges directly related to the tax benefit in EP, giving a net benefit from ongoing tax management to Shell of about $17 million.

Looking forward, the total charges in the corporate sector are likely to run on at just above current levels in Q4 and through next year if interest rates remain unchanged.

A few other general comments.

Cash at the end of the quarter was $4.3 billion, that's cash on the balance sheet.

I mentioned earlier the $2 billion held temporarily for Pennzoil.

Excluding this, our cash balance was closer to the $2 billion level more representative of our average operational requirement.

Capital spend for the quarter was some $5.3 billion.

This included $1.35 billion for the acquisition of [RWE Behr].

But this is not paid until the middle of next year.

Therefore, this amount is not appearing in the cash flow statement, but is reflected as an account -- in the accounts payable balance in our balance sheet.

Capital expense for the year includes the acquisitions of Enterprise, [inaudible], Pennzoil and Behr as well as our organic program.

Total spend for 2002 is likely to be between 24 and $25 billion, of which around $14 billion or so is the organic spend.

This figure includes the CAPEX and exploration programs inherited with the various acquisitions and does not imply a higher annual ceiling on an ongoing basis.

In summary, we had a solid performance showing this quarter, continuing to build on earnings and cash flow generated in the first half of the year.

And at the same time, we've continued to enhance and upgrade our portfolio of businesses, positioning them better for future value creation.

Let me now open for questions.

I'd be grateful if you could restrict your questions to one or maybe at most two, the shopping list approach, it does tend to make it more of a challenge to give your questions the consideration they deserve.

Operator?

Please could you give instructions for questions.

Thank you.

If any parties would like to ask a question, please press the star followed by the 1 on your telephone.

If you wish to cancel this request, please press the star followed by the 2.

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

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

Thank you, the first question comes from Steve Turner.

Please go ahead, sir.

Good afternoon.

I know this is a difficult time of the year to ask this question, but going into your strategic planning review process, are you still confident in your gross target for oil and gas production volumes at 3% to 2005?

Thank you, Steve.

You're right, it's not the best time of year to ask that question, however, original target that we set back in September last year was 3% annual average increase, 2000 to 2005, on the asset base that we had at that time, which of course did not include Enterprise.

We delivered 4% underlying goals last year, our reported headline basis around 1% this year to date.

We are confident in meeting this year's $3.8 million target excluding Enterprise.

However, our base set of assets has changed fairly materially.

We are currently in the process of integrating them in the investment decision, the planning process, we have not yet completed that process, and it's just too early to be more specific about 2003 and the future.

The opportunity set that you now have with Enterprise should give you more options and, therefore, we should expect an increase in your production gross target?

Not necessarily.

We're currently in the process of bringing the assets together and working out where we get the best returns on the dollar invested.

We cannot say anything at the moment going forward and I think you'd appreciate that there's some sensitivity around this issue at the moment.

And it would be inappropriate of me to make any specific statements about the future at this point in time.

Thank you very much.

Thank you, the next question comes from Mr. Richard Franklin.

Please state your company name followed by your question.

Hello, Richard Franklin of Morgan Stanley.

Hi, Richard.

A couple of questions, if I might, firstly on CAPEX, I think your guidance for 2002, 2003 was an average of $12.2 billion a year, you're saying this year looks like a 14 number.

Does that mean that effectively the guidance for the next year is up a little bit or does it mean you'll find savings elsewhere?

And can you give guidance as basically your ongoing run rate, once you take into account perhaps some synergy benefits and some savings.

The second question is actually LNG related.

Have you seen any attempt to renegotiate some of the contracts you have out in the far east, particularly thinking about the pressure that Japan is under, and seeing perhaps a lot of recent contact written at much much lower price levels?

Thank you, Richard.

You are absolutely correct that last December we gave a guideline of $12.2 billion, average over the year 2002, 2003, and again, of course, that was before acquisition of Enterprise and the other deals.

This year, we do expect to be around $14 billion, now, that's a bit plus or minus on the decimal point because of phasing of projects.

What we have seen this year to main effects, one is acquisition of Enterprise itself came with a CAPEX program of well over half a billion.

We haven't yet stopped those projects.

We are continuing with those projects while looking at which ones, although not yet started, we do take forward.

The other effect is expenditure on our organic program as we originally set it out.

We saw overspend on Madagascar and Canada of around a half billion dollars, I think has already been communicated.

We've also taken advantage of a couple of small acquisition opportunities which included Dragen and Pine Dale in the U.S. and there was also an underlying foreign exchange effect as some of our companies are not U.S.-dollar reporters.

And all told, between those effects, they did push us towards the $14 billion.

This did not imply that we expect to continue at $14 billion.

We are currently in that planning process, as I mentioned, and we are looking at level of CAPEX for next year and $12 billion is our starting point because we have a slightly larger portfolio to work on.

And second question, LNG, attempts to renegotiate contracts.

We are regularly in discussion about LNG contracts with customers in Japan and elsewhere in the far east.

Recent contracts for Quangdon and Fujian have certainly come up in the discussions.

However, both of those contracts are 25 years for large volumes, price is not the only issue.

Volume flexibility, sensitivity to oil price, the relationship to oil price are additional issues.

And at this point in time we continue with the long-term contracts we have in place and we are looking obviously to place volume from new projects as they come along.

Price will not be the only factor over time it is reasonable to expect that prices may trend down, but the volume we do expect due grow and feel that we're well positioned to take advantage of that.

The volume growth is likely to be more significant than the price.

Great, thank you.

Thank you, the next question comes from Mr. Jeremy Elgin.

Please state your company name followed by your question.

Good afternoon, Jeremy Elgin from Lehman Brothers.

The cash flow as you pointed out was very very strong.

Up start year on year.

Two-thirds of the improvement in cash flow from Q3 '02 compared with Q3 '01 seems to be coming from movement in working capital this year versus last year.

Could you give us any indication of what comprises the billion dollars release from working capital this year and whether it's likely to be sustainable or might just reverse next quarter?

Thank you, Jeremy, you've done your homework on the balance sheet.

Working capital has been affected by the acquisitions year on year so a direct comparison is not the easiest of things to do.

Contribution from cash flow partly the Q3 performance was helped by the tax payment toward the end of Q2 and the subsequent increase in tax payable in Q3, as in common for cash payments and tax to be paid in Q2.

Year on year, we have seen more prices increase this year to Q3.

Next year, last year we saw them decrease.

If all prices stay at the same level, we have no reason to believe there will be reversal in the working capital as we saw in Q3.

If anything, history suggests at the end of Q4 sees a release of working capital.

Are you suggesting that the working capital tends to fall as the oil price rises?

No, the opposite.

Right.

Okay.

Then the rise in the oil price in Q3 should have led to a flow of money into working capital?

In Q3 itself.

But that's offset by the tax, the tax effect is the biggest single effect.

Right.

So I was thinking of the $1 billion release from working capital, the cash flow statement shows.

You're saying that a big part of that would be the -- just the timing of the tax payment?

Yes, basically.

Okay.

Thanks.

Thank you, the next question comes from Mr. Steve Tieser.

Please state your company name followed by your question.

It's Merrill Lynch.

Good afternoon.

The questions, you were a little bit quiet about the volume target for this year, you said 3.8 million-barrels a day, excluding Enterprise and as I went through and tried to back into what that means for the volumes for 4Q including Enterprise, I was pencilling in 4.275 million.

Does that sound like it's in the range?

The second question is, you gave us the hurricane loss impact for Q3, Q4 could you break that out by quarter and by product?

And does the group have sort of an all-in number for 2002 on what downtime at Brutus and other hopefully nonrepeatable items in 2002 really cost in terms of volumes year to date?

Thanks, Steve. 3.8 million-barrels for the year is an average, Q4 we would expect Enterprise to return back to the Q2 level after the North Sea maintenance.

I actually haven't done the back calculations, I assume if your numbers are on that basis, it would, in fact, be correct.

Seven million barrels are mentioned for the total hurricane impact.

That was roughly equally split between the third and the fourth quarter. each hurricane takes, just over $3 million for each hurricane.

I'm afraid I don't have a breakdown of oil and gas.

I would say overall that was more than our planned hurricanes.

But the overall impact on the annual barrels is less than $10,000, 10,000 barrels compared to the plan.

You ask about the impact from Brutus have problems in the Gulf of Mexico, and just looking -- we were up about 50,000-barrels in Q3 relative to Q2, and slightly more relative to Q1.

On average, 20 to 30,000, maybe another 10,000 for August.

But that sort of indicated levels.

Does that cover the question, Steve?

Right, and that was an annual average for 2002 in terms --

Those were actual figures. 20 to 30 on Brutus and maybe.

Okay, thank you.

Thank you, the next question comes from Mr. Rod McLaine, please state your company name followed by your question.

Credit Suisse First Boston hi there.

Hello.

Just if I can a relatively short shopping list actually.

You talked about resource, I think, of 800 million-barrels so far this year.

And just so -- the four-year number for 2001 was 1.5 billion and obviously reserve replacement last year was a little disappointing.

I suppose the first question is how much of that 800 million is bookable this year?

And the second question is on the U.S. downstream, can you give us any idea what the set of quarterly performance would have been on your reference conditions?

Because obviously to get to your 12% plus target, excluding Pennzoil, you need about 275 million a quarter.

Okay, thanks. 800 million-barrels in addition to resources of which it's probably a million [inaudible] like it to be booked this quarter.

The reserves or the results are spread across quite a few countries and includes Kazitstan, [INAUDIBLE] the Gulf of Mexico in particular, great white, Tahiti, you can see there are projects that will take some time to bring to commercial decisions.

And normal time lag in a couple of years.

And U.S. oil products normalized, we would need to deliver around 250 a quarter, clearly we're still somewhere from that.

I would like to make one point on normalization, it's a bit of an approximation based on the market crudes.

In fact, the differential like heavy crude has just as much impact and technically, we don't take it into the normalization calculation.

It's costing probably as much as the market crude as well.

And, therefore, normalized would be well short of the 275, but if we were to make a correction to the light/heavy, we would get closer to that figure.

Does that help?

That helps a little bit, yep.

Thanks.

The next question comes from Mr. Doug Harrison, please state your company name followed by your question.

Morgan Stanley.

In international R&M, your profits more than doubled in relation to Q2 of 2002 which compares to being down for pretty much all of your competitors in that same period.

My question is can you provide some color on the drivers behind the increase in relation to Q2?

Specifically, you mentioned that lower downtime, modestly higher assigning margins, modestly higher marketing margins and DEA contribution were the primary drivers, were there any other things that had a meaningful impact on a sequential basis, and if so, or if not, could you provide guidances to the delta that each of these factored represented on an absolute percentage basis whatever you might have, as it relates to almost a $400 million increase in profits that you had in relation to Q2?

Sure.

Thinking back to Q2, we had a significant shutdown schedule, most of Canada, the Canadian refining was shut down for most of the quarter and in Europe we had significant shutdowns,[INAUDIBLE].

Our refinery utilization last quarter was below 75, it's now back to more normal level of about 80 to 83%.

We also saw an uptick, although not a large one in the European refining unit margin, therefore, refining overall gave us about, I'd say, 150, plus or minus.

Okay.

Marketing margins overall also were better.

This is a mix of many different countries that had some contribution.

Trading, although I mentioned it was not as attractive as last year, still a weak environment, it was quite a bit more attractive than Q2, $40 million or so, trading and shipping.

Global businesses, we had a contribution, the aviation business, and the marine business both performed pretty well and if I remember correctly, global services, the service business was also up slightly.

Okay.

Will that give some color?

No, it does.

Thanks a lot.

Okay.

Thank you, the next question comes from Mr. Dick Sapeetzen.

Please state your company name followed by your question.

Hello, this is from Financial Bank of the Netherlands.

Could you clarify, maybe I didn't hear you correctly but you were mentioning with regard to your cash position that you were holding about $2 billion for the purchase of Pennzoil.

And in your press release you were mentioning $3 billion.

Maybe I'm missing something, forgive me for that, but could you clarify the difference?

Sure.

Pennzoil transaction overall was around $1.8 billion for the equity.

And we're also assuming just over a billion dollars of debt.

On the first of October, we paid for the equity and we took drawn down cash for that purpose, that was the $2 billion specifically.

Shortly thereafter, we announced a program to repurchase the debt.

In practice, in the system, both in the group and the operating companies, we were holding cash also to repurchase the debt, which will take place over a period, $2 billion roughly on the first of October, roughly another billion for the debt over the next month or so.

Okay.

Thank you very much.

The next question comes from Mr. Neil Perry, please state your company name followed by your question.

Thank you, UBS Warburg.

You talked about return on capital and said over the last 12 months, I think, it's 12% on your normalized conditions, given the last 12 months, basically normalized to 12 months and your range is 13 to 15.

Can you tell us what your Q4 normalized return on capital would have been and when you would hope to be back in your 13 to 15% range?

Thanks, Neil. 12% the commissions were similar to reference conditions, I would highlight that we do this on the rolling 12-month basis.

This 12 months includes not just the nonrecurring part of the U.K. tax effect, but also the current charge, and between them, they have some, like, 60 basis points effect.

We have had higher underlying CAPEX on [INAUDIBLE] that's not yet generating a return.

We have new capital employed in the U.S., such that -- in the U.S. downstream where we're just beginning the synergy deliveries.

As I mentioned earlier, that's not yet driving through to normalized returns.

And when we bought Enterprise, we did state quite clearly, we expected delusions between 1 and 2 % for the group.

Acquisitions, we do take a very conservative approach to the treatment to goodwill.

All figures stated are after goodwill.

All of this takes us down to 12%.

We did state clearly in last December that it is our intention, if we fall below that range to move back into range.

This is subject clearly to getting quite some focus at the moment, in our planning process process.

I can certainly indicate that Q4 is likely to -- the normalized return is likely to be 12% for the year, partly because of the factors I've just outlined and we wouldn't have expected a kick back in one quarter.

However, when we get to the meeting in February, we expect to be able to talk to you about specific events or specific actions on the timing of returning into range.

And also some of the things that we've [INAUDIBLE] just thinking back, we've been working on the bottom end of the portfolio, the $7 billion, we've been divesting assets.

We have been reducing unit costs.

We're still on -- making progress on that.

So both of those activities will help contribute as we go into next year.

Okay.

Well thank you.

But can you just tell me what the total acquisition effects were in the quarter?

You've given us some indication of Enterprise but you got more acquisitions than that.

What's the total acquisition effect?

Well, before -- against the original portfolio of U.S. downstream's about another 40 basis points and 20 on the higher CAPEX.

We haven't yet got any capital employed in for [inaudible] because we haven't paid out the cash and Pennzoil isn't in yet either because that was there effectively Q4 item.

Thank you.

Thank you, the next question comes from Mr. Mark Enolt, please state your company name, followed by your questions.

It's Merrill Lynch, hi Simon.

Hi, Mark.

There have been some recent reports talking about progress in the West East Pipeline in China, can you give flavor there for upstream potential there, what could come to you and what would you be able to boot in 2003?

The second question, can you shed any light on some of these recently proposed petroleum tax changes in the Netherlands, how can they affect earnings and cash flow for the group going forward?

Thanks, Mark.

Exchange in the Netherlands first, if I may, there are discussions at the moment in the Netherlands, just at the proposal stage, given the status of the government changes there, we're not sure exactly what will result.

But as we understand it, there's a proposal to change the depreciation at will facility, which in effect will reduce the flexibility for fiscal depreciation.

It will have no impact on our earnings on the grounds that we do deferred tax accounting anyway.

It will have a relatively minimal impact on our current cash flow.

What it may do is change the attractiveness of new investment, particularly for smaller or marginal fields.

There will be less flexibility in choosing how to invest in those fields so there could be some impact there.

Thanks.

China, West East Pipeline, not likely to be this year.

However, the total reserve [inaudible] basin around [inaudible], that doesn't include the [inaudible] basin where we're in negotiations for potential additional access to reserves.

Our first booking would be considerably less than that on the grounds we would only book at the reserves that are proved up at the first point of making the final investment decision, we then prove the rest of the reserves up as we go through the project.

Great, thanks.

Thank you, the next question comes from Mr. Fred Luther please state your company name.

Bear Stearns.

Hi Simon.

Hi.

Three real quick ones.

First, can you tell us how much DEA contributed to you earnings in the quarter?

Secondly, do you have an estimate of the impact of the refinery returns in the fourth quarter and what sort of delta that might represent versus the third quarter?

And lastly, in response to one of the other questions, I'm not sure if I should take your comments on the reserve base found this year in bookings to mean that the group will not replace production this year?

Thanks, Fred, start easy and got real difficult.

The first question, positive contribution from DEA is around $40 million or so in the quarter.

Refinery turnarounds, I mentioned the fact, I listed almost every refinery in the U.S., all four refineries on the Gulf coast have had issues around production and including Comvent, which was not even producing at the time, the timing of the facility is coming back online.

Therefore, it's relatively difficult to give an immediate answer to your question.

What I can say is that relative to last year, shutdowns in Q3 were roughly $20 million heavier than we had last year and we expect outside the U.S. a similar level of shutdown activity in Q4.

With just the U.S. it's a bit difficult for us to quantify at the moment, because some of those shutdowns are still shut down.

The last question, reserve base, I'm not sure I said too much that indicated exactly what we might do, certainly too early to give any specific figure on this years reserve replacement ratio.

I would highlight that we recognize there's by and large when we take a final investment decision, we have quite a few large FIDs in the pipeline at the moment, Kashagan, West East Pipeline, the timing of these may well slip into next year.

The other point that did I make, although they're large reserve bases, we don't recognize the entire reserve, when we initially take FID.

You would have heard various figures flashing around on Kashagan.

It's not likely we'll be taking one-sixth of that total figure the first time we recognize reserve.

Does that help?

Yes, I think that's good.

Thanks.

Thank you.

The next question comes from Mr. Ben van Hooven.

Please state your company name followed by your question.

Hi, this is Ben van Hooven [INAUDIBLE] .As far as some details on the power, can you say what the current commitment still for various installations to be built?

Are there any ones scheduled which have been scrapped, any plans scrapped?

And I suppose these are a big part in your low results in the U.S. GMP.

So can you give us a flavor of how we're going forward?

Thanks, yes, I think it was you.

The end of the quarter, we had just under four megawatts or is it gigawatts, in fact, of capacity up and running within Intergen.

We expect to increase that to over five in the latter part of this year, which will be a result of a couple of plants starting up in Turkey and in Australia.

We currently have projects under development that would take us up to around eight gigawatts.

We have not cancelled any projects that are currently under construction.

We did mention in the Q2 results, though, that given that given that clearly the power markets have changed and not for the better over the past year, 18 months, we have asked the Intergen management team to review the strategy, to come back with a restructuring plan which essentially has happened now.

Activities will be refocused on completing the current projects, operating them through the most economic effect, and there will be less of an emphasis on finding and developing new projects.

The straight answer is no cancellations, no major changes in the comportfolio but less of an emphasis on searching for new projects.

I understand that, but in terms of outstanding CAPEX and in terms of your use going forwards, what's your outlook there?

The power business is not just Intergen, it includes power trading, gas and power trading in the U.S. include coal, including long-term [INAUDIBLE] agreements we talked about before, and challenge in Europe as the gas and power trader in the market.

Clearly the current sparks spread on both sides of the Atlantic, as depressed results this is year, not materially as last year, because there was limited contribution last year as well, but there was a small negative in the power sector overall at the moment, and marketing and trading is roughly flat.

Going forward, it's difficult to take a view on the spot, but if it stays where it currently is, then we would expect the results to stay just on the wrong side of positive.

Okay, thank you.

Thanks.

Thank you, the next question comes from Mr. J.J. Trainor.

Please state your company name followed by your question.

Hello, it's J.J.

Trainer from Deutsche Banc.

Can you hear me, Simon?

Yes, I can.

A couple questions, I'm not sure if I missed the number, you said what you thought you got on cost savings on the German downstream, have you got a cash cost savings number for the U.S. downstream for the quarter or the year to date?

And then a couple of quickies on the upstream.

What's the status of gas sales from the Sacolin project?

And one of your competitors or partners, but someone else in the sheer water project took a write-off.

What's the status of that?

Thank you, J.J.

The German figure was $60 million, which is that item, the $14 million we talked about earlier in the year.

The U.S., the run rate, we talked about 160 heading towards 200 for the quarter, but we're going back to where, you know, the figures that we discussed in September, and the phasing.

It's not something we would talk specifically about until Q4 because it's such a major contributor to our underlying improvements.

And [INAUDIBLE], related to the earlier question, we are actively engaged in discussions with potential customers in the far east, Japan, Korea, and Taiwan, and if and when they mature, we will talk about them in public.

One of our partners, better ask one of our partners ultimately, that we understand that if you acquire something you probably allocate some of the premium on acquisition to the assets.

We don't have that issue.

We will not -- we have no need to recognize a write-down in the sheer water affect.

Just going back to the Sacolyn question, the spending going into the project there, I think I'm right in saying but the gas isn't sold.

Is that what you normally do for a project like that?

I guess what are the risks associated with that?

Just to be clear on sheer water, you're not planning to take a write-down on that?

No, we are not planning to take a write-down on sheer water.

There's no need to do so.

Spending in going into Sacolyn, on essentially design work, and reasonability work around the original FID.

It's on the order of $50 million a quarter that we're seeing on Sacolyn and other projects.

Yes, it is difficult to incur costs on these long-term major project opportunities in advance of taking an investment decision.

At the very least, we'd due a front-end engineering design which gets us to a design concept that partners and banks can agree so.

And that is a significant at the point, a significant step, costs associated with it.

But it is entirely normal.

The results at the moment, the level is a little bit higher than someone might normally see, for several long-term projects.

Sorry to push you on this, but the FID would, therefore, be contingent on some sort of take or pay contract for the gas?

It's likely that we would need some of the gas to be locked up in long-term contracts before we take an FID.

That is correct.

Okay.

Thanks very much.

Thank you.

The next question comes from Mr. Paul Spedding.

Please state your company name, followed by your question.

[inaudible] good afternoon, Simon.

I heard you say something in your introduction about tax planning.

I thought you said there was some ongoing benefit.

Can you clarify that, please?

Ongoing tax management, the -- obviously, we spent quite some time and effort ensuring that we optimize our tax position across many countries.

We took the one off hit in the U.K. this quarter.

It is normal for us to have pluses and minuses in tax, which is why we do not account for them as a special.

It is normal for the figure to go up and down, and to be material.

We felt that given the credit this quarter was so material, we needed to make this clear.

The credit in the EP from several items, was a total of $120 million credit for EP.

But an offsetting charge, just because of the way our group accounting policies and audit agreements work, there is an offsetting $50 million in the corporate sector, for the net impact of ongoing normal tax management was around $17 million credit for the group.

That in part offset the $300 million one off debit.

But that's not ongoing though.

The 300 is not ongoing.

The $17 million is not ongoing either, it goes up and down quarter on quarter.

Thank you.

Thank you.

The next question comes from Mr. Mark Gilman.

Please state your company name followed by your question.

First Albany.

Simon, can you hear me?

Yes, I hear you fine.

A couple of things, the minority interest in this quarter suggest that a much higher level of earnings for subsidiaries with a minority.

What kind of rate is that?

Two things relative to Q2. [INAUDIBLE] remove the minority interest in Germany.

Shell Canada, the refineries were back onstream, and I think the other one is Sacolyn, where production only runs for six months a year and Q3 is the only quarter that has a full three months of production included.

Okay.

Just to check something, you account for rural gas on a cost basis, is that correct, and, therefore, book only dividends?

Correct, cost dividends, dividends used to be recognized in the second quarter.

So there's no dividend in Q3, typically $40 million a year, although we did have a special one last year with a higher figure.

I'm having a little bit of trouble understanding your comments regarding the downtime in the U.S. oil products, particularly in light of the discussions in Houston last month.

Can you clarify what portion of what you're talking about for the fourth quarter is storm-related versus unplanned versus planned maintenance?

All right.

Comvent was the big one, the refinery was already shut down for major modifications anyway.

The shutdown impacted the -- so the hurricane impacted the work on the shutdown and also lengthened the time to bring the plant back up again.

In fact, the refinery is still shut down.

Deer Park, we lost some production, I think the units just come back a few days ago. [inaudible] and NORCO, both impacted by the hurricane, both unplanned.

Martinez and Los Angeles were both planned.

Well, actually, the Delaware refinery also has had some unplanned shutdown problems.

Seven refineries have had issues, three of them were fully unplanned, two already had planned shutdowns that had been extended, and two had planned shutdowns.

Two-thirds of the issues were related to the hurricane and maybe a third were not.

Okay, thanks.

Just one final one.

The EA field in Nigeria, can you put some volume to bes on that, I assume that's the field subject to the MOU?

The project itself should come onstream this quarter, the volumes around 100,000-barrels total.

Our share, 100,000.

We're about a third, should be up and running by the end of the quarter.

On the MOU, you said explain the question?

No, I assume that EA is subject to the Nigerian MOU, it's not the deep water terms?

Did you hear me, Simon?

Yes, sorry, it's not a CSV, that's correct.

They're related to the standard terms, yes.

Okay.

Could you just clarify what adjustments you made on the Enterprise DDNA, what was the source or the cause of those adjustments?

In the second quarter, we attempted to Enterprise as a complete the single entity we've on the completed the acquisition in the third quarter, we've allocated all the assets to individual countries within our own reporting system.

As we allocated out the purchase price to individual assets, we ended up with slight different rate of unit depreciation than we initially expected.

So that's increased by 30, $40 million a quarter relative to previous.

Okay.

It was not a makeup portion of that?

That's going forward?

That's going forward, yes.

It's not make up.

The current level of depreciation is indicative going forward, not the Q2.

Is that clear?

Yes.

Thank you, Simon.

Thanks.

Thank you.

The next question comes from Mr. Gordon Grey.

Please state your company name, followed by your question.

Yes, Gordon Grey of JP Morgan.

Hi, Simon, just a couple of minor questions on the upstream volume side of things.

I wonder if you could tell us a little bit behind the bounce from Q2 to Q3, eastern oil volumes, secondly, if you could give us a feel for the magnitude of oil,, of production from the other acquisitions, the minor, the dragen interest, the pine Dale assets, and so on.

Thanks, Gordon.

The other eastern hemisphere is primarily related to LNG in Oman and Malaysia and [inaudible] The oil is Sacolyn, which I mentioned earlier, we got three must knows full production in there.

The impact from Tagen and pine Dale is on the order of 20,000-barrels a day.

Uhm-hmm.

Okay.

Great, thanks.

Okay?

Yes, thanks.

Thank you, the next question comes from Mr. Michael Mayer.

Please state your company name followed by your question.

Prudential Securities, sorry Simon if you've answered this, but my phone faded out a few times.

You cited during the press release and during the course of the call, some other one-time items that were not considered special items, it seems to me that they netted up to about 6-cent as share.

Is that about correct, the $300 million for the deferred tax, the $120 million tax benefit partly offset by $50 million of interest charges, and then the $50 million in U.S. inventory?

They all are one-time writes and you're correct on the per share impact.

But I would guess that you are probably correct.

And my second question was was -- [inaudible] interpretation that they're all one, are correct.

The second question would be what is the exact production forecast or either the fourth quarter or full year, including Enterprise and all the known storm downtime, et cetera?

3.8 million-barrels a day is what we would expect to deliver, plus three-quarters of Enterprise at 240.

So that's -- I have 180 on top of 3980, that would be the average for the year.

Okay, very good.

Thank you.

Thank you.

One last question, I think.

Thank you, sir, that comes from Mr. Daniel, please state your company name.

Hello Simon.

I would like to ask several questions on EMP.

First on gas production in the U.S., there was significant increase from both Q2 and the last year.

Could you tell us what was the new fields and also the impact of the acquisition,ing a also the underlying trend in cost reduction in the upstream.

Could you quantify the impact of the [inaudible] and also the impact of long-term project cost that distorted the figures figures?

Okay, gas in the U.S. [inaudible] contributes were [inaudible] and the Alex field, and the pine Dale acquisition in the Rockies, and basically the -- those three contributed.

EP costs, you asked the exchange rate impact and the impact on long-term.

When we [inaudible] 3% unit cost target, we were cleared underlying unit costs and was in effect a productivity measure, not necessarily an absolute cost measure.

The productivity measure relates to activities directly related to operations.

We do correct the figure, the unit cost figure for exchange rate effects or for feasibility studies that are one off.

And, therefore, there is no impact on delivering the 3% unit cost from the two items that you mentioned.

I'm not sure I picked up everything on the first question.

Is there anything I didn't cover there?

Yes, thank you.

Could you go over all the impact on the quarter for the exchange rate and the feasibility studies?

It's around $100 million.

Okay.

And the one off longer term.

Thank you.

Okay.

I think we have no further questions, thank you very much for your time and your questions.

I look forward to seeing you again next year.

Thank you.

Thank you.

This concludes the conference call today.

Thank you for participating.