殼牌 (SHEL) 2003 Q3 法說會逐字稿

... national conference call on Thursday, October 23, 2003 13:15 hours U.K. time.

Your check person is Mr. Simon Henry.

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

Welcome to the Royal Dutch Shell Q3 2003 results conference call.

I'm Simon Henry, Head of Group Investor Relations.

Before starting I'd like to say to our disclaimer about forward-looking statements, which you can find on page eight of the quarterly results announcement and as I provide a brief statement on the course of events and results before moving on to Q&As.

First, a reminder of the various developments in reporting requirements this year including specifically the introduction of Regulation G as part of the Sarbanes-Oxley Act in the U.S.A.

Third quarter earnings contain a number of unusual items.

These are not separately reported as special items, as they may once have been.

Net impact on after tax Q3 income is a charge of around $330 million.

I'll refer later to these items in some more detail.

As in earlier courses, our base performance comments on adjusted CCS earnings for ease of understanding.

Although again you should note we're giving equal prominence to net income on a Dutch and U.S.

GAAP basis in formal reporting.

Again, a result of Sarbanes-Oxley.

Before moving on to earnings, it's worthwhile reviewing some of our progress against the stated strategy this year.

Our strategy is clear, more upstream and GAAP, profitable downstream growth, new income streams, and a focus on specified geographical areas.

This year mostly has been a remarkable year for the number and the quality of the strategic milestones achieved.

Qatar Gas to Liquid and Athabasca oil sands are important moves into unconventional fuels both huge projects with great potential for growth in the future.

In the global L&G business we've seen a number of developments that will extend our existing leadership of this industry for some time to come.

Secondly, we were the largest integrated oil and gas project in the industry, establishing a material presence in Russia.

With new supply capacity in Nigeria and Malaysia continuing to both wells, we've seen good progress on potential future supply project in Australia, that's globe one, and Venezuela.

L&G sales contract will continue to build into the three major markets in the U.S. and Europe and Japan.

Re-gas capacity in North America continues to build.

Ultimately in Mexico was sanctioned in this quarter and permits were obtained to Baca, California on the West Coast of North America.

Our form U.S. gas re-gas capacity by the end of 2006, now exceeds one BCF today.

Of which we, Shell, will take price exposure on maybe 40%.

Now I'll put it in perspective for you.

Based on just our existing projects, our share of L&G into the U.S. will increase group exposure to the U.S. gas prices by the equivalent of 25% of current group U.S. natural gas production.

This figure could increase if the other negotiations we're currently engaged in prove successful.

We had a series of firsts in production, first, offshore Nigeria, first international offshore in Brazil, and the first oil sands.

The future octanes in four very important resources holding countries were in end.

Key steps for the increased share in giant Kashagan field and Kazakhstan, a final investment decision on Seline in Western Siberia, Saudi Arabia and exploration agreement, and the production share agreements with the signed head for the East China Sea.

A little closer to home, the U.K.

Noah (ph) agreement on cross border development enabled the agreements on the exports of Norwegian wet gas from Stockholm to the U.K. through our infrastructure.

And should open the way to possible development of the Alman Langer (ph) field.

All of these contribute to the future built earlier in a very material way.

As an indicator, the first phases of the four big projects, Athabasca, Sacoline (ph) , Kashagan, and Qatar, represent a Shell share of investments around $15 billion, with $3 billion already spent.

They'll develop over six billion barrels of oil equivalent in reserve and give peak production of 600,000 barrels of oil equivalent a day or higher.

And each of these projects has potential for growth beyond that first phase.

In addition to this, we certainly expected to device of around $2 billion of assets this year.

We've already exceeded that figure by some way.

Total proceeds to date are $3.4 billion.

We have divested assets of very attractive prices, primarily in Europe and the U.S. where we've realized prices of up to $12 for barrel of oil equivalent.

And nearly $2 billion of income generated by this activity is expected to offset non-recurring charges this year.

Cash generated have helped fund incremental investments this year.

The asset sales and impairment charges both derived from a significant focus on and review of strategic options for pro performing or non-strategic assets.

These processes will continue.

Moving on to the results.

In comparing the results with Q3 of 2002, we should recognize the last few months with even much more favorable oil and gas-pricing environment than last year.

And also, that refining and marketing conditions have been better this year.

Our second vest, the petro chemical environment has remained very challenging.

In practice, Q3 this year was the worst environment for chemicals overall that either Q3 last year or Q2 earlier in 2003.

The overall environment helped our businesses deliver net income of $2.7 billion and adjusted CCS earnings of $2.6 billion.

The latter figure includes the $330 million of unusual charges mentioned earlier.

The year to date net income of $10.8 billion is a nine-month record for the group.

Reported largely, now includes the impact of the 2002 acquisitions.

Also, the change in the canteen treatment of $3.4 billion of liabilities now included in capital employed.

This latter point was told for you in the Q2 results announcement.

Rolling 12-month return on capital was 16% on a net income basis and 16.5% on a CCS cold cost to supplies earning basis.

As we mentioned in the second quarter, this figure has been reduced by foreign exchange movements relative to previous year and by the accounting changes.

And the impact on return on capital here is over 1%.

Quarter again showed strong cash gen from operations, after tax and interest of $5.2 billion.

Tax from operations in the first nine months is over $17 billion, mixed when supplemented by over $3 billion of divestment proceeds.

Both EP and OP businesses have benefited from contributions from acquisitions made last year, building on the billion dollars of cash generated by the four deals in '02.

The figure of cash generated from the $16 billion of acquisitions is now well over $2 billion, just over year on average of ownership.

This cash has been applied in accordance with our financial framework as we've spelled out over time.

Dividends paid out, well over $6 billion, our first priority.

Nine-month cap ex of just under $10 billion was inline with the full year estimates of $14 billion.

We concluded the payment for the Dajo (ph) acquisition last year.

That added a further $1.3 billion.

We've invested over $2 billion in hedging and employee share options and buying out minority interest in U.S. upstream ventures and in contributions to pension funds.

And finally, over $2.5 billion has been applied to reduce debt.

The priorities for cash application remain prudent balance sheet management and disciplined capital investment.

Steady progress continues to be made in delivering synergies from each of the four acquisitions building on the numbers we reported in Q2 and then delivering the projected 3% reduction in underlying unit costs.

And now I'll briefly to reviews you in the businesses and then I'll open the call for Q&A.

First, exploration and production, EP adjusted earnings of $2.1 billion or 22% higher than a year ago.

High oil and gas price realizations were the main factor.

Production was affected by divestments and by higher prices in production sharing contracts.

Divestments had an impact of around $60,000 of oil equivalent per day relative to the third quarter last year.

The PFC price affect flushed the previously abide permanent change to the specific entitlement under one of our PFCs.

This difference between the two courses was around 100,000 BOE equivalent today, a negative impact.

Adjusted into these factors on a comparable basis, oil production volumes were down 1% and gas production reduced by 5%.

Overall production on this basis was down 2%.

Again, adjusting for divestments, production for 2003 is expected to be around 1% below target and that recognizes divestments around 35-40,000 barrels this on impact on the full year.

In Q3, new production of 200,000 barrels of oil equivalent today is more than offset by declines in material sales of over 210,000 barrels oil equivalent today as noted in the results announcement.

In addition, a variety of operational issues in the North Sea and North America reduced production by around 90,000 barrels of oil equivalent per day.

Shut down of the burnt platform following the unfortunate incident in September in the North Sea, was the largest single factor.

And the impact of this will extend well into quarter four.

EP capital investments of $2.4 billion in the quarter was in line with expectations.

And this quarter included the purchase of the increased share in Kashagan, expected to be paid out in Q4.

Turning to gas and power, GP had another strong underlying performance.

This was matched by the impairment sector and partly offset by the once half P&L impact of the change in the canteen treatment of the towing agreement.

Moving the net $239 million impact of these items, underlying earnings of just over $300 million reflected the strength of the L&G performance.

Despite the loss of the L&G volumes following the exit from Malaysia Sartees (ph) , increased in the remaining L&G supply pipeline saw particularly in Nigeria, was more than compensated in the year to date.

In the power sector, the impairments reflect continued poor economic conditions.

The strategy outlined a year ago continues with focus on operational performance of the existing assets, cost reduction, limited development activity, and portfolio rationalization.

Q3 marketing and trading results and the midstream results both improved relative to last year by around $60 million, excluding the unusual charge, or credit in this case.

In all products, adjusted CCS earnings remain strong at $880 million, 67% ahead of last year.

With year to date earnings approaching $3 billion, more than double last year.

Improved global refining margins contributed to the year-on-year improvement as did improved marketing performance.

Both refining and marketing benefited from lower costs as the acquisition synergies were delivered, although these reductions were offset by the weak dollar and the higher pension costs.

Both Waza (ph) and the U.S.A. showed substantial increases in earnings.

Overall refinery availability this year to date is over 95%.

Availability is a theoretical figure and not reflective the actual use of a refinery.

Utilization provides a much better guide to use or throughput in a plan.

In Q3, compared with 2002 refine to, refining utilization was up 1.4% in the world outside the U.S. and up half a percentage point in the U.S.

Globally, the year-to-date improvement in utilization has been 1.4%.

In the U.S.A., we have planned to shut down activity in California and unplanned shutdowns were equivalent to 7.9% of capacity.

The incidents on aggregation of various events and unit slowdowns - there was no specific major incident.

It's worth noting that this -- the industry average figure on this indicates or in the U.S. is around 7%.

And that our target of 4% represents first quartile performance.

In the U.S., planned and unplanned shutdowns in the quarter cost around $80 million pretax more than Q3 last year.

The majority of this is due to the higher unit margin that was available.

Outside the U.S., the equivalent increase was around $40 million, again, pretax.

Shutdown activity in Q4 is expected to be around normal levels in both the U.S. and the world outside the U.S.

In both the U.S. and WOUSA, margins were around 15% higher than last year.

In WOUSA, this improvement also reflects the positive contribution from differentiated fields and other marketing programs.

Progress on upgrading the retail networks continues.

In the U.S., over 3,000 Texaco stations are now rebranded plus nearly 4,000 Shell stations revamped.

That's about a third of the total network that we started with.

And over 2,200 sites removed from the network.

In Germany, nearly 600 sites have been rebranded to Shell in the last few months, on target, on budget.

Move onto chemicals.

We recorded earnings of $12 million in the quarter and this is after the inclusion of $56 million of restructuring and impairment charges.

Some parts of our portfolio, specifically SMPO, Fino (ph) , Aromatics, and the ethylene oxide, ethylene glycol businesses are doing well and overall volumes are holding up.

Other parts of the portfolio, for example, polyurethanes, are doing less well.

The result essentially reflects a delayed economic recovery.

Chemicals are on track with a 3% reduction [Inaudible] underlying unit cost commitment and Methala (ph) is delivering on its cost commitments.

Cash flow from chemicals remains more than sufficient to fund cap ex at the bottom of the cycle.

Manufacturing capacity utilization in chemicals is still in the low 80%.

The technical availability, again, remains high.

It's over 90%.

Product demand in chemicals remains uncertain and patchy across geographies and product group.

There are very few signs to give us a clear indication of the development of the industry demand or utilization for the rest of this year.

Other industry segments have a loss of $160 million compared to the gain of $4 million a year ago.

This loss was mainly driven by an impairment late into Shell's solar business.

The loan demand continues to grow here.

Market conditions have proved particularly difficult for all buyers in the solar industry.

Portfolio rationalization including plant closures and cost reductions have been implemented but future prospects for the business are materially worse than previously projected.

In the corporate segment, net cost of $141 million were lower than Q3 last year, mainly as a result of an unusual credit of $93 million.

Capital employed added to the balance-sheet as a result of applying 1046 will have an ongoing impact on interest charges in this sector.

In the absence of any other major changes in overall debt, interest and exchange rates, some $250 million, net costs remains indicative of the level of quarterly cost going forward in the corporate segment.

Depreciation in the quarter totaled $3 billion including the impact of impairment and changes in exchange rates.

Underlying annual depreciation is expected to be over $9 billion subject to exchange rate and other factors.

At the end of the quarter, the gross debt ratio is 22% and cash holdings amounted just over $2 billion.

The increase in the ratio since the end of Q2 is mainly driven by accounting changes although the interim dividend from the settlement today after last year's acquisition were both paid in the quarter.

It's good sense to be reducing the debt ratio while oil prices remain high.

Hence, the balance-sheet will continue to take priority in cash allocation decisions.

To conclude, in the last few months, we've continued and extended last year with excellent progress in developing our business portfolio within our strategic and financial framework.

And, we've continued to deliver good profitability and very strong cash flow.

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

Thank you very much, sir.

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

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

And before asking your questions, we would ask that you state your name and your organization.

Thank you.

The first question's from Mr. Jonathan Wright.

Please go ahead, sir.

Hello, Simon.

It's John Wright from Citigroup.

Couple of questions.

First of all, one about your underlying returns.

Clearly, there's some external effects having an impact there and you're somewhat at a disadvantage because you don't adjust to them whereas others do.

You said something that, you know, where you'll continue to report on the six month basis or should we expect to any change?

And secondly, you talked of $9 billion depreciation.

Clearly it was impacted in this quarter by the impairments.

Could you give us the underlying amounts of depreciation in this quarter excluding impairments?

Thanks, John.

Underlying returns.

Yes, we do report six months late and we will expect to do -- continue to do so until we have advised otherwise.

We talked in the middle of the air about the impact of one of two things, external issues on underlying returns, and this affects both the reported return and the normalized return.

Major two issues were exchange rates and changes in accounting treatment.

In the middle of the year we talked about up to 2% impact.

Given exchange rates as they were then and the accounting changes we could foresee at the time.

That remains the case, that we would expect underlying returns or normalized return to be impacted by up to 2%.

However, we haven't restated the target on the grounds that we control neither of the above.

And therefore, to state that we state the targets would be vulnerable to future changes.

We said we would aim to deliver certain underlying economic improvements that are cash based.

The ones I just mentioned affects and the accounting changes that are essentially non-cash movements.

We will continue to report as transparently as possible on delivering the underlying improvements, which are primarily costs and synergies but also the portfolio upgrading and some volume improvements.

On depreciation, the underlying is around $9 billion and a - that's for the year.

That clearly is impacted directly by our effects for the quarter; the underlying is around $2.4 billion.

And does that cover the question, John?

That does lovely.

Thank you.

Thank you.

The next question is from Mr. Neil Perry.

Please go ahead, sir.

Hi, Simon.

It's Neil Perry from UBS.

I have two questions.

One, could you just comment a little bit on the marketing volumes in the United States because they're down by about 5%?

And I thought that the plan was you lost no more than around a percent in terms of marketing volumes as you rebranded and cut down the number of sites.

And secondly, on those underlying returns, on the profitability.

There's been some concern that you are lagging on your targets in the U.S. downstream restructuring as a whole.

Can you give us any update on that? 'Cause your comment seem to be fairly profitable in synergies but you certainly refinery availability perspective don't seem to be doing as well as you had hoped.

Thanks, Neil.

Mark to volumes in the U.S. were down around 6, 7%.

They are affected by two major factors.

One, in the commercial business, this is not the retail business, which you have talked about, we have been pursuing a strategy of jettisoning the low margin, high volume business because it adds very little, it nothing, to the bottom line, so there's an impact there simply from following our underlying strategy.

In the retail business, which is more of the sales, yes you're correct but we would look to retain a fair bit of the volume from rebranding and from reducing the site numbers.

In the quarter year on year also for the year to date, we do see an additional impact from the number of sites that are actually closed from rebranding, which has had quite some impact.

The reduction in the retail volumes alone, year on year, is about 5%, just under 5%.

About two-thirds of that is from reduced site numbers.

And the rest is primarily from the sites that are being closed.

We are seeing on rebranded sites, that's the Texaco rebrand, between 4 and 5% average uptake on volumes through those sites.

That has been the case ever since we started the rebranding program and is being sustained.

Because we have so much of the site down at any one time, we're maybe not seeing all of that flowing through to the bottom line.

Moving onto the underlying returns in the U.S., we still have some way to go in refining.

There were three areas of improvement we were looking to achieve - cost, retail and refining.

Cost mentioned synergy is pretty much on track.

And our 3% reduction in the U.S. also on track.

Retail is delivering pretty much as we expected, but on a - we're aiming for a network of around 16,000 sites.

We've had 7,000 rebrands.

Not all of them actually need rebranding.

But, clearly, we won't see the full bottom-line benefit until we finish that program, which will not be until the end of next year.

On refining, we mentioned 7.9% refinery unplanned shutdown time in Q3.

And the 7.5% is year to date.

We are targeting 4%.

That is a significant improvement potential that we still retain there.

We saw, in dollar terms, quite a significant amount of money left on the table this quarter.

I mentioned $80 million relative to last year pretax.

And that was primarily because of the high margins available on the West Coast.

We had a series of incidents.

They were not - no big major incidents, but the slowdown - we were impacted in Delaware, Puget Sound and I believe one of the Gulf Coast refineries.

But the program we engaged on there is part integrity improvement, part management process improvement.

We're pretty much on track with delivering the integrity improvement and we're very focused on delivering the management improvement that will go with it.

If we reach the 4% target there, it will go a long way to meeting the return target for 2004 in the U.S.

The last thing I would point out is Pennzoil.

Pennzoil quite the state (ph) , making pretty good progress there, a year on.

We've reduced the work force by around 600 people.

We've taken three of the seven LOBP (ph) s out [Inaudible] blending plants.

And we are pretty much ahead of track on delivering the synergies there.

Globally, we're going to start that the first of January and we're becoming a stronger player in lubricants as a result.

Does that cover things now?

Yes.

Thanks very much.

Thank you.

OK.

Thank you.

And the next question is from Mr. Tyler Dann.

Please go ahead, sir.

Yes.

Good morning.

Thanks for your time this morning.

My questions are actually related to foreign exchange, first of all.

I'm - I was on the call, but I didn't recall whether you had mentioned the specific impact of foreign exchange effects for this particular quarter, relative to the previous end, the previous year.

No, I didn't mention the specific facts - is the simple answer.

There are two key main effects from FX - one on the net income and one on the balance sheet.

The net income impact of the 10% move in the euro to dollar exchange rate, when the dollar weakens, is somewhere between 103, $100 million on net income and cash.

And that is a range that reflects the fact that not all currencies move in line with the euro.

On the balance sheet, the same sensitivity - $2-3 billion on the balance sheet.

And of course, that is all numb (ph) cash.

On average, this year, relative to last year, the exchange rates moved by just under 15% Euro.

The sensitivities I just mentioned you can multiply by one and a half and I guess for any quarter versus any other quarter, that would be that the same sensitivities apply.

I think just as an indicator, Q3 exchange rate wasn't that much different to the Q2 exchange rate, but relative to a year ago, it's about 13% lower.

OK, very good.

Thank you for that.

Question on the downstream please.

The cost of the re-branding effort, could you please specify how much you've incurred to date in the United States and then outside of the United States and how are these cost related to the budget?

The total cost of the re-branding program was to be around $500 million, some of which in the U.S.

Hopefully the feedback's going down. $500 million in the U.S., some cap ex, some op ex.

We're pretty much on plan with that so -- half way through that.

And yes, we did include it in the budget.

Expect to conclude that sometime towards the end of next year.

And [Inaudible] 600 sites, that was in this year's target -- this year's budget and has been basically delivered that program there.

Pro rata basis, that's somewhat less than $100 million there.

OK.

Thanks very much and then my final question is just to clarify, you're 2003 production when you kind of adjust for all of the asset sales and I believe the PSC effect, you mentioned you'd be 1% below target on a life for like (ph) basis.

Can I confirm that that is primarily related to Brent?

I think automatically, it probably is close to Brent, but also there's an issue in decline rates in the U.S.

Gulf, particularly in the Bruces (ph) platform.

Brent for the quarter or U.K., primarily Brent was ran 40,000 barrels a day and could be 60 to 70,000 barrels a day to Q4 depending on the time, Dan.

U.S. decline rates have been higher than we had originally projected.

And that, quarter-on-quarter impact was about 90,000.

So those are the two main reasons that we're likely to be about 1% below target for the year.

OK.

Thanks very much.

Thank you.

The next question's from Mr. Fred Leuffer.

Please go ahead, sir.

Hi, Simon.

How are you doing?

Not bad.

Three unrelated questions.

First, can you tell us how much capital you have dedicated to Russia with Celime (ph) and Sakhalin?

Second, can you comment at all oil and gas production buying outlook for next year?

And lastly, can you give us some guidance on interest expense in the fourth-quarter?

Thanks, Fred.

Russia current commitment, $10 billion total for Sakhalin of which the Shell share will be 55%.

That's $5.5 billion.

We will spend around $1 billion this year and it's ramping up obviously from this year into next year on stream in 2007.

Celime (ph) , the total commitment would be $1 billion of which our share is 50% to be spent what we're starting to spend now and will be on stream in 2006.

That's the total exposure of $6 billion Shell share.

We're also have long been in discussions with Gaz Prom around those gas prospects.

And we'll be interested in other opportunities as they arise in Russia.

No $6 billion dedicated but only around a billion dollars currently stand.

That is on top of the first phase of Sakhalin, which in itself was also around a billion dollars.

That's already producing condensate.

Oil and gas production outlook for 2004, we're currently in our planning process.

The only guideline I have for you is that when we spoke to the market at the end of March is we were looking at a relatively flat profile, '03, '04, '05.

That reflected the fact that a lot of the large projects in our portfolio come through in the '06, '07 period.

We do have coming on stream next year a couple of major projects, Bonga, NaKika, and Wholestein (ph) , Bonga in Nigeria, the other two in the Gulf of Mexico.

And we will be finalizing the plan over the next month or so.

Interest charges, I mentioned that guidance for the total corporate sector would be around $250 million per quarter.

The interest charge is likely to increase because of this accounting treatment to the off sheet liability that were previously off sheet.

The increase is only around $50 million a quarter plus or minus.

It's time to bid on interest rate.

It's how they currently stand plus that kind of order of magnitude.

Does that help?

Thank you very much.

Thank you and the next question from Mr. Mark Iannotti (ph) .

Please go ahead, sir.

Hi, Simon.

Hi, Dean.

Hi, Mark (ph) .

Hi.

Quick question, I may be missing something, but I'm looking at the cash flow statement and it's showing a profit on the sale of assets.

And I guess that's a profit from your $1.1 billion of disposals in the quarter.

Can you tell us if we have actuals up in the segments, please?

And how it relates to the $130 million of one off shore you mentioned in your opening remarks?

The profit in the quarter, the 315, is primarily U.S.

Gulf of Mexico sale of assets to Apache.

It shows up.

That's a pre-tax figure, of course, 315.

The way we show it.

So the post-tax figure is in EP U.S. earnings.

It is included in the 330.

EP itself has that profit and has a couple of impairments and one or two other unusuals.

So the EP net unusual charge is virtually zero.

So materially not important but in terms of where would it be as the impairments are not in the U.S. and the earnings are, the P&L on the asset sale, is in the U.S.

Brilliant.

Thanks for clearing that up.

Sure.

Thank you, the next question is from Mr. JJ Traynor.

Please go ahead, sir.

JJ Traynor from Deutsche Bank.

Simon, I'm just looking at Judy's points and its call in.

It's about the underlying returns on the newswires.

I guess I don't understand.

And then you've had the accounting changes, right?

So why doesn't she just reset the target?

Or is return on capital employed as a fixing dollar on price not the right way to measure the performance on the company anywhere?

So it's a question there.

And then secondly, I was interested to see that Brutus has gone into decline.

I was a bit surprised at that because that's quite a young field.

Are there are kind of technical issues at Brutus?

Thanks, JJ.

Underlying returns, actually Judy to the wise exactly what I had said, but we already mentioned earlier in the year.

Yes, we know the accounting changes today.

No, we don't know the accounting changes by the end of 2004 and specifically IAS, International Accounting Standards, will be introduced on first of January 2005.

Therefore, it would be inappropriate for us to prejudge that impact.

And just, anecdotally, we told you a level of capital employee impact we expected from Fin 46 (ph) in the middle of the year.

They were still working on that accounting change - the details of it - only a few weeks ago.

And in fact, delaying the implementation of it - at the company's option.

So even where you can see the change coming, to know the exact implications of it requires a very good team of auditors.

And I mentioned the foreign exchange impact.

That is even more - we're rationally more sensitive to that than accounting changes most likely.

And it moves quite significantly on the normalized return, more so than the reported return because of the mechanics of the calculation.

Whether that's right or wrong is not for those to judge maybe.

But it is up to 2%.

If the exchange rate moves another 10%, then it'll be up to 3%.

So we're not going to restate a target on those grounds.

What we will do - just maybe take the opportunity to say where did this return on capital target come from?

It comes from a cash based financial framework.

We talked about it in December 2001.

Thirteen percent was the return required on $65 billion of assets to generate cash in a conservative environment that would enable us to build the dividend, to invest at $12 billion.

That was how it all fitted together.

We now have a capital base on 50% higher than that.

We have a cash flow, which is considerably stronger than it was then.

And that is the underlying economic substance that we talked about in Q2 and that is what we are driving the business on.

There - ultimately there - normalize or ought to, for (ph) wear it well, depending on factors outside our control.

But we manage to the underlying cash.

And just on Brutus - Brutus came on stream in late - or mid to late 2001.

It is a deepwater project.

Typically, they have very high early returns and reach plateau very early on in the field life.

Brutus actually reached its payback in cash terms earlier this year - somewhere around the April, May time.

It has made money already.

We expected it to do into decline.

It has, however, gone into decline faster that we thought.

Part of the reason is compartmentalization of reservoir, something I guess you probably know more than I do about.

And that is something we're working on from a technical viewpoint at the moment.

We also have seen decline in the over (ph) platform area as well.

And that's been a water cut (ph) issue over time.

So, put together, year on year, there's quite a significant reduction there in Brutus and auger (ph) .

Future prospects for Brutus - we are looking at the reservoir engineering.

We see - there's a couple of satellite sales (ph) to bring in next year and in 2005.

We should be able to hold the decline rate roughly where it is.

OK, Simon.

Thanks very much.

Thank you.

The next question is from Mr. Paul King.

Please go ahead, sir.

Hi, Simon.

How are you?

Paul King of UBS.

Hi, Paul.

Question on downstream.

Looking at the current refining and marketing condition, we saw some deterioration, particularly in the European and Asia area.

Do you see any voluntary run-cuts in either Europe or Asia and are you profitable in those two areas right now?

Thanks, Paul.

Right now, downstream margins are looking less attractive than they have been previously in the year.

In terms of voluntary run-cuts, we have no additional in Europe.

We've had cuts from quite long standing voluntary run-cuts in the far East, particularly in Singapore.

So, we ourselves are not seeing run-cuts.

We can't speak for other players in the industry.

We have, as I mentioned earlier, a normal planned shut down program for the quarter.

Has the magnitude of your voluntary run-cuts in the Singapore area changed as we saw some of the recent changes in margins?

Not materially, no.

OK.

Thank you very much, Simon.

Thanks.

Thank you.

The next question's from Jeremy Eldin.

Please go ahead, sir.

Good afternoon, guys.

Can you tell me one simple question?

I noticed the tax rate increased in the quarter versus the first half of the year and that seems rather more than I'd have expected given the appreciation in oil price and also I think you've got net tax credits.

Was there anything extra going on in that tax rate and was there any extra tax charge within WOUSA E&P.

An extra tax charge in WOUSA E&P?

Yes.

Straight answer to the last one is yes.

The impairments that we took are by in large non-tax deductible.

That's added nearly 4% to the tax rate for the quarter.

We'd expect going forward more of the 43 plus or minus a percentage point is more to be expected but the primary factor this quarter is non-tax deductible impairment charges.

That's great.

OK.

Thanks a lot.

OK.

Thank you.

The next question's from Mr. Rob MacLean.

Please go ahead, sir.

Hi Simon.

It's Rob MacLean from CSFB.

Two questions.

On the U.S. down stream, your unplanned downtime in 2002 was 7.8% and you're running for the nine months at I think 7.5% this year.

Does that mean that sort of you're expecting a stat change in this performance in 2004 down to 4% or do we expect or do you expect to sort of continuing a gradual improvement in that number because my understanding is you can't get to the 12% number without actual achieving very close to the 4% figure.

And the second question is on the balance-sheet.

You talked quite a lot in your earlier remarks about the balance-sheet, and I guess my question is, your gearing is 22% at the end of the quarter.

Your in the bottom end of your sort of gearing range.

The impression I got was that you would actually at these sorts of oil prices feel much more comfortable to be at a lower level or gearing.

Can you just comment on that issue as well please?

Sure.

Fining in the U.S.

I think I mentioned earlier, 7.9% if correct.

Improvements depend on fixing the [Inaudible] and improving the management processes.

For financial improvements, there's a double level here.

One, merely from having the capacity available and secondly, if that capacity is available and reliable and we brought the product into places we know it should be, and we plan for it to be, the upside from a logistics and a supply trading management activity is a double bonus.

So we are talking couple hundred million dollars, maybe, relative to where we are today on the table, annual figure that is not a costly one.

We look at the rate of progress.

Yes, you're right, we probably do need 4% to get to our overall return.

And we would currently target the 4% by the end of next year.

The process change is both gradual in its nature and gradual in its effect.

And it's not something we would except to see as a step change.

And for any given refinery the integrity may change as a step change, but on a network of nine refineries, I think you see gradual improvement there as well.

I can only say that I'm really wildly, the management focus on this having seen Rob Routs on Tuesday.

And he is confident that that target can be achieved by the end of next year.

Balance sheet gearing, 22% is the headline gearing.

I think we mentioned earlier in the year as well from a credit rating agency viewpoint, the headline gearing is one aspect but they also look at a series of other items.

They always have.

And the recognition of they, the liabilities this quarter is an example of one of the things that the rating agencies have always taken into account.

They also look at pension funds.

They look at operating leases.

They look at guarantees and a variety of other things.

When we take those into account, we look at the, where the gearing is and the fact that the oil price remains pretty high levels historically.

We would expect to be bringing the gearing ratio down.

We're becoming more comfortable with where it is.

The 20-30% range we've laid out in the past has always been indicative of what we felt matched a triple A rated company.

And that's one important factor for us in managing this.

So it hit 22%.

We're quite comfortable with the direction its moving in.

And so I'm just going back on the U.S. downstream.

I mean, the 12% next year.

I mean you're suggesting that you will not be on the run rate, you know, through the year because obviously the trial percent is based on the four quarter ruling average in 2004.

The implication of what you're saying is that you may be at that run rate by the end of the year and into sort of 2005, I guess.

That's one implication.

I wouldn't jump the steps.

As I mentioned earlier, we're in the middle of the planning process and I didn't just restate the target for 2004, but I did say from a refining perspective it's a gradual process that we would expect to have finished the process by the end of next year.

Yes.

Thanks very much.

Thank you, the next question from Mr. Neil McMahon.

Please go ahead, sir.

Hi, Simon.

Neil McMahon with Sanford Bernstein.

Hi, Neil.

Hi, just a question back on the Gulf of Mexico deepwater.

Brutus is obviously a set of your TLP assets in the Gulf of Mexico.

Just wondering if the effects you're seeing in Brutus as a deepwater field is going to be typical of other deepwater fields you've got in the Gulf of Mexico.

And indeed, in what you're investing in Nigeria and other parts of the world in the deepwater.

Should we expect these much higher decline rates from the deepwater than potentially we've got modeled into the, our models?

The second point was just looking at the costs as well in the upstream part of the business.

Looks like the costs backing out from a net income for borrow number seem to have gone up over the quarter and over the last few quarters.

Just wondering if you could comment on that?

And then finally there seems to be 35 million of impairment charges in E&P in the UK and South America.

Just wondering if you could go into where exactly those impairment charges were.

OK.

Thanks, Neil.

I believe you're probably better qualified than I am to talk about reservoir compartmentalization in the Gulf of Mexico.

What we're seeing with Brutus, benefited two years of production history and rather more detailed reservoir models, we've learned more about that particular accumulation.

It is more complex than we anticipated.

We have been applying those technical and operational skills we have to get a better understanding - more seismic, better production data.

And yes, we can see the challenge in the reservoir and there's no easy fix on this particular reservoir.

It would be wrong to read across to all other reservoirs in the Gulf of Mexico and we have been producing offshore there five, six years in the deep water.

And basins like the Mars Basin (ph) , we've continued to grow production over time and realized additional reserves, particularly from satellite fields (ph) .

Working on compartmentalized reservoir is not too different from working the satellites across.

And the severity we see at Brutus is rather unique and we don't see a read across.

And costs - quarter on quarter seem to increase.

From which of that our underlying unit costs, we were hopefully clear back in February, but this is a productivity based target.

It is not a slash and burn high level cost number.

Therefore, underlying means we target those costs which are activity related and we adjust - we adjust for things like lower pension firm credit.

For foreign exchange movements, we seen most of the foreign exchange movements I talked about earlier is a cost issue.

It raises the costs quite significantly.

And we also talked about higher pension fund credits - around 500 million year to date pretax.

Sorry - full year, not year to date.

Relative to last year.

So both those factors are pushing costs up.

We - I guess those were probably the two main factors.

And impairment charges in the upstream - we didn't actually give a figure for that.

Just the net figure.

But there are two material impairments.

One is in Argentina - Bank America (ph) - where gamets (ph) - it's partly a production reserve issues to what the future prospects of that business actually are, recognizing after various efforts to improve the future prospects, the assets are less than we had previously expected.

And in the U.K., it's an aggregation of fields in the North Sea.

Just as background, we go through this impairment process every year at this time of year, looking at the carrying value of the assets, partly for our own planning purposes and partly for audit purposes.

In terms of what led to the impairments, it's normal practice.

I would make a point, actually, that when we do this, we choose to take the charge immediately and several players in the industry prefer merely just to then accelerate depreciation out over a period of time.

And therefore, you need to read that into any comparisons that you would wish to make.

Does that cover everything now?

Yes.

That's great.

Thanks, Simon.

Thank you.

Your next question is from Mr. Nick Nichol (ph) .

Please go ahead, sir.

Hi.

It's Peter Nichol (ph) at ABN.

Hi, Simon.

Hi, Peter.

Couple questions on the upstream.

Just what you mentioned there, the impairment of the North Sea.

Are those fields from Shell portfolio or from things that you've acquired with Enterprise.

Second one on the E&P was wondered if you could give us a volume figure for the annualized production you sold this year and sort of proved reserves impact that we'll see at the end of the year.

And then the last one, just going back to this sort of balance-sheet and the sort of the target gearing.

Is this sort of a balance-sheet or gearing level that we should think of where you'd be sort of comfortable to sort of consider a share of buybacks or is it -- are you thinking of changing the target range?

Thanks for that.

The first question's probably the easiest.

It's the Enterprise contributions not material to the U.K.

The annualized impact of the divestments.

Those that we have already announced, the production, those that we've already announced this year's around 70,000 barrels.

The impact from this year is about 35,000 barrels, so the incremental impact next year will be about 35, 40 year (ph) thousand barrel.

I think that's the question you asked.

I'm not ...

Yes, that's great.

Balance-sheet target buy-backs.

Good question.

Buy-backs before we get to considering buy-backs, we have to make the two criteria.

One, cash flows -- strong cash flows above the requirements for dividends and the organic investment program and two, the gearing in a position where we're really quite comfortable.

At the moment, we're still in the, "let's get more comfortable with the gearing phase".

I certainly have no comment on whether the buy-backs will be considered as of next year but they are the two factors to consider and it's an and condition, not either or.

We need cash flow and the balance-sheet and we've been -- we've had one of those conditions fall forth (ph) this year, but not the other one.

OK, thanks.

OK.

Thank you.

The next question's from Mr. Bert Van Hugenhause (ph) .

Please go ahead, sir.

Good afternoon, Simon.

A few questions.

First on the divestments, could you fill us in?

I had expected a larger number than the 911.

We had debenture (ph) for about $500 million [Inaudible] assets for 445.

Than we had [Inaudible] .

We had the Mongrows (ph) assets gilamunts (ph) .

Could you fill us in if any of those are to come in Q4?

And also in divestments, does the fact that we -- that you realize the higher figure this year mean that next year we should be a bit below the $2 billion in a few of these statements or for $2 billion on average for 2003 and 2004.

I think the first question is probably relatively easy.

Michigan (ph) was completed in October and therefore, will appear in the fourth-quarter divestments.

That was $445 million.

All the other items that you mentioned are in the third-quarter.

Great.

On going forward, $3.4 billion this year indication was at least $2 billion in each year.

Again, plan in progress but I think we can expect $2 billion at least next year as well.

Right.

And the other question I had was about the impairments in power.

You took on a $50 million some time ago.

This time, $240 million.

Should you expect anymore impairments in the quarters ahead?

The current capital employed in the past factors is under $1 billion.

This time we looked at two things in the past.

InterGen and Two Jabar (ph) in Brazil.

Two Jabar (ph) specific case where the Brazilian markets and the venture is positioning with its customers - its agreements with its customers have been renegotiated and looking at the market.

And the auctions for the asset, we chose to take that write down now.

On InterGen this particular quarter, this is write down of the goodwill on the original acquisition of InterGen.

If you go back a few years we actually acquired InterGen and then restructured it with Bechtel.

There is no goodwill left on InterGen.

This is our assessment of the best future assessment of the prospects for InterGen, taking into account what we see as a, the pile market, particularly in the United States.

It's the U.S., really, where we've seen the decline.

And note essentially it takes longer for supply demand to come back into balance and for the stock spread to become attractive again.

Quite difficult for me to say unequivocally there will be no more impairment.

It's obviously dependent on the market.

We are looking at certain assets in the InterGen portfolio for divestment.

And it's always entirely possible that a divestment in IPP market is not the top of the cycle, necessarily.

There could be some impact there.

Great.

Thanks very much.

Thank you, the next question is from Ms. Irene Himone (ph) .

Please go ahead.

Simon, good morning.

It's Irene Himone (ph) from Morgan Stanley.

Afternoon, Irene (ph) .

You made this quite clear your balance sheet is taking priority in terms of the cash or location decisions since you referred to your cash base and natural framework.

My question is are you prepared to give some indication, if we look at your cash flows and your reference environment as to how far away are we from balancing those, what is the deficit?

And what is the chance?

In other words, are we getting any closer?

Good question.

I'd say without going back to reference environment, I think we're pretty close to the $19 billion that we've talked about as being the cash requirement.

That's $19 billion in nine months over 18 maybe not quite 19.

At a reference condition basis, I honestly don't have an underlying number.

What I would say is we have seen improvements year on year from the acquisitions.

And the cash, the conversion of income into cash ratio, presumably some of you may calculate, has improved quite significantly over the years.

And most of the issues we talked about earlier that are depressing earnings have little or no cash impact.

And therefore I think it's fair to say that the progress on the cash flow is better than you might see the progress on the reported return.

But I don't have specific figures.

OK.

Thank you.

Thank you, the next question is from Mr. Mark Gilman.

Please go ahead, sir.

Simon, good afternoon.

Had a couple of things, if you wouldn't mind.

First could you update us on the Teaga (ph) fire situation and when you expect that first range of the back up and operating?

Secondly, the other Eastern hemisphere natural gas volumes were a bit lower than frankly I was looking for.

Could you comment on that?

Thirdly, just a bit more difficult, perhaps the accounting adjustments for the tolling contracts.

Could you walk us through what you'd done there with a particular eye toward how we might gauge the impact of these activities on future period results?

Thanks, Mark.

Moving from detail petroleum engineering to accounting.

I'll see what I can do.

An update on Teaga (ph) fire.

We don't have a specific date for it to come back on-line, but we're not expecting it until early next year, maybe Q1, Q2.

It's not been specified yet by the operator.

Other Eastern Hemisphere gas volumes were indeed lower.

I think in Q1 I mentioned that we have seen the change in the - pardon me - the terms of one of the production sharing contracts in that region that would take around 60,000 barrels a day.

Of the reported production in gas in OEH and that is a permanent reduction.

That doesn't come back.

So that will happen every quarter.

In addition, in the quarter, gas prices have continued to increase.

They follow the crude price roughly by three months.

And that reduces our share in production sharing contracts.

We have quite a significant number of PSCs in the other Eastern Hemisphere.

We are seeing quite some growth in Nigeria, which falls in that category, of course.

And I was trying to think - probably no other factor there.

So I think those are the main drivers.

Accounting adjustments for totaling agreements.

Firstly, the balance sheet.

We have taken on - it's something like $2.7 billion for totaling agreements.

It's not all of the 3.4 we spoke about - $2.7 billion has gone into fixed asset, tangible fixed asset.

These are now being treated as a capital lease and therefore, the other side of the entry is in debt.

There is a short and a long-term component.

This number is less than the total future commitments because of - I mentioned earlier, the specific accounting agreements of - accounting standards have to be looked at very carefully in some detail as to exactly what gets capitalized for each agreement.

On profit and loss statement, what we have effective done is move from a mark-to-market basis, where the totaling agreements were part of the chain of transactions where we would be producing gas selling gas.

Trade in the stock spread and selling power.

All of these transactions were mark-to-market and the impacts on the P&L would be a relatively small number each quarter, plus or minus, depending on the mark-to-market.

Going forward, the accounting rules changed and we are obliged - although the front and the back end of the transaction - the gas and the power will still be mark-to-market.

The middle piece, the totaling agreement will be accounted for on similar to a capital lease.

We see, in the P&L, a depreciation charge totaling - cash payment totaling payment related to operating.

And we see an interest charge on the lease and the interest income on expense statement in the corporate segment.

Gas and power will see an increase in its earnings and there will be an increase in income and therefore a reduction in earnings in the corporate segment.

The overall impact, as we go through a cycle isn't that much.

But because of the change from mark-to-market to accrual type accounting, the volatility, quarter on quarter, could be noticeable for gas and power.

It could be up to or even exceeding $50 million per quarter.

And that is the impact of the change in accounting definitions.

So the more volatility, probably not that much impact on net income after tax, but there will be plus earnings in gas and power and negative earnings in corporate.

Last point, cash flow entirely neutral, but cash transactions flow from the Tony (ph) agreements are exactly the same as they otherwise would have been.

Simon, the credit in this quarter, that's a one time kind of affect?

Yes, for that one.

That's the one time affect.

There was a mark to market and we've had to write that back as a credit because we're not longer marking to market so it's just the straights right back of the credit.

And that's a gain?

Gain.

It is, yes.

It offsets the impairments.

I'm almost sorry I asked, but thanks.

OK, Mark.

Thank you.

The next question's from Mr. Paul Spedding (ph) .

Please go ahead, sir.

Hi, it's Paul Spedding (ph) from Dresdner.

Just a quick question on your non-U.S. gas realizations.

They didn't change materially during the quarter.

I wasn't sure if that was just a production mix issue with Europe falling away quite sharply although there was nothing else going on.

Perhaps if you could just give us some guidance of what the outlook was for the fourth-quarter.

Non-U.S. gas realizations, they include Canada.

Though, we saw three factors.

Canada went down I believe quarter-on-quarter.

Europe went down quarter-on-quarter.

The rest of the world went up.

Europe tends to follow product prices over a long term contract also have an impact.

Canada came down because it's primarily linked to Henry Hubb (ph) and the rest of the world went up on average partly related to the PSC affects I spoke about earlier.

Where's it going in Q4?

Canadian will follow Henry Hubb (ph) .

Europe, if it follows the product prices, it's likely to recover somewhat and the world that side, Europe and North America should improve somewhat.

Thank you.

Thank you.

The next question's from Mr. John Rigsy (ph) .

Please go ahead with your question.

Simon, all of my questions have been answered, thanks.

OK.

Thank you.

Mr. Michael Mayer.

Please go ahead.

Yes, good afternoon, Simon.

Three questions.

Can you tell us currently what is the capital employed in chemical and what is your target return under normalized conditions?

Second, given the various operating issues and asset sales, what is the production forecast for the fourth-quarter of this year?

And third, your targeting approximate 4% improvement in U.S. refining reliability.

What is your estimate of the contribution to earnings if you deliver on that?

Thanks.

The capital employed in chemical is around $10 billion.

The expectation that reference conditions is 12%.

We are -- that's quite a significant reduction over the past few years in terms of capital employed.

Something like $15 billion, not that long ago.

Q4 production, I didn't have any sales figures for Q4 production but if I go back to the way I started, the target, that's $16 and just for clarity, let me tell you, 1% short of target.

That's a $16 target and that is by definition impacted by production share and contract in prices.

The year to date total PSC impacts has been about 120,000 barrels a day, so just to help the differences between headline and - headline volumes and those reported at 16.

That 120,000 oil prices stay where they are today you expect that to be factor for the full year, roughly that.

And you can maybe work backwards from that to your likely volumes you had in mind of both headline level would be about 1% below last year and the target of 16 with that 1% below the target of 4.1, both excluding the impact of the divestments of about $35,000.

Hopefully that made sense.

The ...

I was actually looking for specific number but.

I'm helping myself.

Fair enough.

Get it for you and give you a call later.

All right.

On the 4% improvement on plant down time, it would certainly depend on the margins.

We've - I think spoken before.

I think the 4% relative to where we are at the moment is not quite short of $100 million.

And then last year when we in Houston, of course again we talked about that second boost I mentioned a few minutes ago.

If we were to supply envelope as we do elsewhere in the world, we think that's worth about 30 cents a barrel.

We only do that if you've got reliability on the physical side and your marketing that work in place.

And that works out about $120 million pre-tax and maybe $80 million post-tax.

So you put the two together, you fill up with $150 maybe towards $200 million.

Very good.

Thank you.

Thank you, the next question is from Mr. Mark Flannery.

Please go ahead, sir.

Hi, everyone.

It's Mark Flannery here.

Hi, Mark.

Hi.

I got another question on the U.S. downstream, sorry about that.

But could you please clarify that to meet your target by the end of next year will you have to have reversed the volume lost in retail, let's say the 5% number that you're talking about today?

In other words, will you have to get the volume numbers up to meet the target as well as achieve the refining on planned downtime?

Some of that will have to come back, yes.

But that's two things there.

One we won't, by the end of next year we won't have all the short stations down at any one time, any given time.

And secondly, all of them at work should be doing the volume uptake, the 4-5% that we've seen.

There is one other issue that we haven't originally projected.

And that's the overall demand in the U.S. market.

And we are seeing demand somewhat less than we'd originally projected.

And what we can then achieve in economic terms from that demand remains to be seen.

But the overall level of demand is certainly lower.

And we wouldn't have a projection on next year on that particular factor.

And how is - I mean is that like a 1% or a 2% type number up to now?

I understand you're not going to give us a forecast.

One percent in terms of total demand or volumes?

In terms of the impact on your volumes.

For example, a weaker background is going to impact your volumes by roughly how much?

Is overall demand down 1%, 2% as you're seeing it?

We have seen overall demand down by maybe 2, 3% earlier in the year.

I don't really have figures for the third quarter 'cause they're not available yet.

And clearly, our market share is going to be important in that environment [Inaudible] understand that what matters then is our market share.

And the volumes we're achieving per site in the market share, we were seeing improving earlier in the year.

And again, the third quarter figures are not available yet.

So, the directional trends are all in the right way.

OK.

Great.

Thanks very much.

OK.

Thank you.

The next question is from Mr. Jason Penny (ph) .

Please go ahead, sir.

Hi, Simon.

It's Jason (ph) from ING.

Hi, Jason (ph) .

I was interested in the likely spend for the new expiration opportunities in Saudi Arabia and also in the East China Sea.

Also, what level of development cap ex is likely over the next few years for these opportunities?

And would that we considered an incremental opportunity or is it in the annual targets for spend?

And then, finally, what volumes were associated with the assets divested in the Michiken (ph) sale?

OK.

Saudi Arabia is essentially a four-year expiration license.

Our share - 40%.

It is part of a - the normal budgeted process and our share year on year is not going to be huge.

If we have a [Inaudible] there and there is a development program that springs from [Inaudible] expiration, then clearly it would potentially be quite a major investment.

But that will depend very clearly on the results of the expiration.

Offshore China - the agreements covered both expiration and potential development.

Just be clear, it was a production share in agreements that were signed.

The final investment decision has not yet been taken.

That we would expect that next year, based on some of the appraisal work that we currently are engaged in.

That investment level - indicative level is potentially a billion dollars on the reserves already identified there.

But clearly, that would again depend on expiration activity between now and then and also finalizing the investment - the field development proposal.

The last question was divestment in Michigan (ph) with 20,000 barrels or the equivalent per day, effective in October.

So that will impact Q4 onwards.

Thank you very much.

Thank you.

The next question is from Mr. Don Nielson (ph) .

Please go ahead, sir.

Hello.

Good afternoon.

I have two questions on the E&P or the follow-up of previous one, I'm afraid.

First, on the cost reduction, you said that many factors pushed costs upwards.

But in your underlying target of 3%, where do you stand now?

And in terms of declined rate in the U.S., what do you project in the next few years in terms of underlying decline rate in your U.S. production?

And lastly, an accounting question - in terms of minority interest, I was surprised by your high number - $118 (ph) million - was there any special charge in back there?

Thanks, Don (ph) .

Cost reduction [Inaudible] .

The underlying unit costs are roughly flat and the main driver has been the lower production that projected.

The actual underlying - the total operating costs have reduced, but so has the underlying production.

And therefore, the total reduction is fairly minimal.

One - I've mentioned the total cost in synergies were on track.

You can see that all products and chemicals are more than compensating for that position in E&P.

And fine (ph) rate in the U.S., we can't actually give a figure for this.

The overall portfolio in the U.S., it is -- although we have spoken on individual projects, it's typical to expect 15%, 20% decline per year in offshore production environment but that is often offset by being in satellite fields as the capacity frees up on the platform and that over a period of time is how we generate very attractive returns in the U.S.

Of the five hubs that we have in that particular strategy is one that will continue in the future.

We see declines on the main fields we bring the satellites.

I'd like to point out a minority interest and perhaps a reminder for all Sakhalin currently produces for six months a year.

It's major production is in Q3.

It's highest in for most of the winter and Sakhalin minority interest shows up disproportionately in Q3.

But there was no specific impact from the special [Inaudible] as you mentioned in impairment and so on.

Not a major one although I guess InterGen.

Yes, you said that ...

InterGen wouldn't actually sign on thinking -- I think of one done.

Thank you.

OK.

I believe we have no further questions.

I'd like to close the call.

So I thank you.

If there are any further questions that any of you wish to follow up, please be -- feel free to call my self or any of my team.

Thank you.

And this concludes the Shell International Conference Call.

Thank you for participating.