殼牌 (SHEL) 2010 Q3 法說會逐字稿

Ladies and gentlemen, welcome to the Royal Dutch Shell Q3 results announcement call.

There will be a presentation followed by a Q-and-A session.

(Operator Instructions) I would like to introduce the host, Mr.

Simon Henry.

Thank you, operator.

Welcome to the Royal Dutch Shell third quarter 2010 results presentation.

First, please, could you take a moment to read the cautionary statement, then I'll take you through the results, then leave plenty of time for your questions.

Our current cost of supply earnings excluding identified items were $4.9 billion in the third quarter.

That's an earnings per share increase of over 85% compared with the third quarter of 2009.

Results rebounded from year-ago levels driven by execution of our own strategy and by more favorable industry conditions.

I'll give you the details in a moment but both the upstream and the downstream earnings increased substantially here.

In fact, approximately doubled.

This is a better performance from Shell and the quarter underlines that we are delivering on our strategy which is a reminder is all about performance focus, delivering growth targets from new projects in 2012, creating new options for future growth out beyond 2012.

Our continuous improvement programs are going well.

We took $3.5 billion as underlying costs in 2009 and up to the middle of this year, and we've now completed over $2 billion of asset sales this year from the non-core portfolio.

We are in a delivery window for new growth.

Our third quarter production increased by 5% overall, and we started up new production at the end of the quarter in Canada's oil sands in the mining.

Building for the future, we took the final investment decision on two new deep water projects, and we made and completed $5.5 billion worth of acquisitions in the quarter.

So let me first give you a few more details on the results, starting with the macro environment.

So if you look at the macro picture compared with the third quarter of last year, oil and gas prices have increased.

However, the spread between the oil and the natural gas realizations remains pretty wide on a historical basis.

That's mainly driven by the more rapid increase in oil prices compared to North American natural gas prices.

That said, we have seen the year-over-year increase in the European natural gas realizations this quarter which reverses the declining trend in the first half of 2010.

That, of course, is a positive for our earnings.

Chemicals margins have increased in most regions against the third quarter last year, and we're seeing some good earnings in the segment.

Refining conditions remain pretty challenging for the industry, although they are actually better than they were a year ago.

Turning now to our own earnings, the headline current cost it of supply earnings of $3.5 billion for the quarter, they include identified items of $1.4 billion.

You are probably aware that we normally test our carrying values on the balance sheet of assets during the third quarter every year.

The results today do include impairments in both the upstream and the downstream positions.

In the downstream, we impaired various refining assets, principally in Europe and Asia Pacific.

In the upstream, we carried out a comprehensive review of Canada's heavy oil position, looking at the latest reservoir data, the most recent cost outlook and the developments in our strategy, which impacts the priority for our investment decisions.

And going forward, we are going to be focusing on growth potential and profitability in the oil sands mining around the Athabasca oil sands project and on [in-situ] resources of the common creek project in the Peace River deposit.

The impairment today in the upstream reflect changes in carrying values of around $1 billion and what is a rather scattered in-situ and cold heavy oil position is primarily in legacy BlackRock positions.

That's the acquisition made by Shell Canada in 2006.

Mostly these are non-producing assets.

They're not part of common creek or the mining portfolio.

Our third quarter CCS earnings excluding identified items were $4.9 billion.

EPS increased 86% compared to last year.

The cash flow from operations for the quarter was $9 billion so strong performance.

And the dividend for the quarter is unchanged at $0.42 per share.

We are now offering a Scrip Dividend Programme from third quarter 2010 where eligible shareholders can take the dividend of new shares.

You can find all the information about that process on our website.

So the quarter saw higher earnings in both the upstream and downstream.

So let me move on to more detail about that.

Firstly, of course, the upstream.

Excluding the identified items, upstream earnings increased by 106%, more than doubled to $3.4 billion in the third quarter.

The main drivers here were essentially our own increased volumes, lower costs.

We did see higher oil and gas prices, and we also had an increased dividend from an LNG joint venture.

The upstream production increased by some 5% Q3-to-Q3.

The production from new sales and ramp-ups was 180,000 barrels of oil equivalent a day.

That more than offset field declines.

Our LNG sales volumes grew by 22%.

This was underpinned by Nigeria LNG where in practice the gas supply picture has improved as a result of bringing on the new Gbaran-Ubie project in Nigeria.

We essential reached full capacity at Nigeria LNG by the end of the third quarter.

Let me update you on Shell's activities in the offshore US.

In the Gulf of Mexico, in light of the drilling moratorium after the oil spill.

We have continued some of our development activities during the moratorium in the deep water.

For example, a restart of the Perdido platform in September after maintenance there.

However, we had four rigs in the Gulf and another one in Alaska, floating rigs, and four platform rigs that are idled in the US throughout the third quarter because of the moratorium.

As a result, we took a $59 million charge for these impacts in the third quarter as an identified item.

That brings the total charge so far related to the moratorium to $115 million.

There will likely be further charges in the fourth quarter.

The moratorium and the delay to our drilling is an opportunity lost for Shell.

We've seen 230,000 barrels of oil equivalent per day production in the Gulf in the first nine months this year.

That's 10,000 barrels a day oil equivalent lower than it would have been ex the moratorium.

And although the moratorium is now being lifted, there is going to be (inaudible) effect on future production because we haven't been able to drill this year.

For 2011, we're currently expecting around 220,000 barrels of oil equivalent per day production in the Gulf.

That's around 40,000 barrels a day lower than it would have been had the moratorium not been in place.

There could be further impacts into 2012.

We just don't know yet.

Turning now to the downstream, excluding the identified items again, the downstream CCS earnings increased substantially from the third quarter 2009 to some $1.5 billion in total.

Chemicals' earnings, driven by industry margins and the impact of strategy delivery, these included the effect of new capacity addition in Singapore, selling into the Asian market and investments to increase our capability to crack lighter feedstock including ethane in the US Gulf coast.

There was some improvement in refining but refining conditions do remain difficult, especially in other in Europe, which still remains important refining center for Shell.

The losses in the refining sector in the quarter were around $90 million.

That's similar to the previous quarter, second quarter of 2010, but it's a much better position than the $450 million loss in the third quarter we saw last year.

The marketing earnings increased from year-ago level reflecting higher earnings from lubricants partially offset by slightly lower trading and retail contributions, and marketing and trading overall delivered very strong results against the historical quarterly trend at the top end of the range.

Worth noting at the moment that we are experiencing some downtime in the cat crackers in [Pernis] in the Netherlands and Port Arthur in the US.

That's -- we are currently closed down for maintenance and some repairs.

It we expect to see some impact, probably relatively small, in the fourth quarter's results.

So those are the earnings.

I'll turn to the cash flow.

The cash generation on a rolling 12-month four-quarter basis was $35.3 billion, including $3 .9 billion of divestment proceeds.

So broadly speaking, the cash flow for the first three quarters or nine months of this year was actually higher than the whole of 2009.

You will remember that we're targeting a 50% to 80% increase in cash flow from ops, compared with that 2009 base, by 2012, over a three-year period, and whether 50% to 80% depends on whether our price is $60 or $80.

Our acquisitions in the third quarter were $5.5 billion, reflecting the closure of both the East Resources acquisition in the US and the Arrow acquisition in Australia.

So these acquisitions combined with our ongoing capital spending programs have resulted in a small increase in the balance sheet gearing during the quarter.

At the end of the quarter, the gearing was 19%, compared with 17% at the end of the second quarter.

That's still very comfortably within the zero to 70% gearing range that we include in the financing framework for the Company.

We continue to watch the cash position and balance sheet very closely as I'm sure you're aware, and we are putting particular emphasis within the Company on cost management and on capital efficiency.

Moving on to the portfolio, we made good progress with portfolio development in the quarter.

We've now started up five as of the 13 new projects coming on-line in the two-year period for 2010 and 2011.

This now includes the start-up of the 100,000 barrel a day expansion to the Athabasca oil sands project we started up a second mine.

It's now called Jackpine.

The production in Jackpine will ramp up in 2011 as we also bring on the new capacity at the Scotford Upgrader plant, and that will come on stream early next year and that process is the heavy oil into the more valuable lighter products.

Now, having two mines in service now means that we can start to reduce the unit costs from the synergies we see from the scale we now have there.

So we now expect to reduce the cash production costs by over $3 per barrel for the entire oil sands project.

Looking out beyond 2012, we made progress with crystallizing some of our longer term options.

We have recently taken the final investment decision, what we call FID, on two deepwater project.

Firstly in the Gulf of Mexico, we launched the 100,000 barrel a day Mars B development.

That's in the Mars basin.

And in deepwater Brazil offshore, we're now going ahead with the second phase of the BC-10 project.

Turning to acquisitions and divestments, this is, of course, a very important part of our focus on continuously improving and upgrading the quality of the portfolio.

First, on the acquisitions, we made progress on several bolt-on deals in the quarter.

The acquisition of East Resources takes our North American tight gas potential resource base to some 40 Tcf, or well over six billion barrels of oil equivalent.

Arrow Energy in Australia, which we bought in a 50/50 approach with PetroChina is a coal-bed methane play.

We expect that will support a six million to seven million ton per year LNG project in Queensland, exporting into Asia.

In the downstream we signed binding agreements with Cosan to form the downstream marketing and sugar cane-based biofuels joint venture in Brazil.

We are expecting to book a capital contribution of some $1.6 billion as part of this transaction when it closes sometime in the first half of 2011.

On the asset sales side, in the quarter we agreed to sell our 13,000 barrel a day late-life position in Statfjord in Norway for $225 million, and we completed the disposal of three leases in Nigeria, and that's equivalent to around 15,000 barrels a day at Shell's current production.

We're making selective investments in Nigeria to strengthen the long term position there, and at the same time, focusing our footprint and encouraging more involvement by indigenous companies, Nigerian companies, through the ongoing divestment program.

On our downstream divestment program, we agreed to sell our 90,000 barrel a day Heide refinery in Germany to Klesh.

We agreed to that during the quarter, and we've continued to market other positions.

You will hopefully have noticed or seen that yesterday we announced the sale of our Swedish and Finnish downstream business including a refinery in Gothenburg.

Overall, these disposals are all part of the target to sell some $7 billion to $8 billion of assets over the two-year period, 2010 to 2011.

And we've now achieved $2.2 billion by the end of the third quarter this year.

Worth restating, this is a value-driven program.

No fire sales.

We're in no rush to do this.

We're looking for value.

And this is all part of the continuous improvement strategy around the portfolio.

So just to summarize before I move to Q&A, excluding identified items, current cost of supplies earnings per share increased over 85% versus 2009.

Performance in the quarter underlines delivery of strategy.

We're making good progress on all three strategic themes -- The short-term focus, performance focus, delivering growth on projects, on the creation of new options.

Our priorities remain for a sharper delivery of strategy.

We aim for profitable growth and a more competitive performance.

We believe we're making good progress against all of these targets, and we are very much on track for growth.

With that, I would like to move to your questions.

Please could you try and restrict yourself to just one or two each so that everyone has an opportunity to ask a question, and look forward to hearing them.

Operator, please could you now poll for questions?

Thank you.

We will now begin the Q&A session.

(Operator Instructions) Our first question comes from Michele Della Vigna from Goldman Sachs.

Please go ahead with your question.

Hi, Simon.

I had two questions.

The first one is regarding your marketing performance.

It looked very well in the quarter.

I was wondering how sustainable that is in the coming quarters.

And secondly, I was wondering if you could give us some guidance in terms of how your exploration program is going in Brazil, and in particular, and the BMS-54 well.

Thank you, Michele.

Marketing performance, we do split out our marketing and trading for you on a quarterly basis.

Typically we trade in the range $800 million to $1.2 billion per quarter across marketing and trading.

We were just above $1.2 billion this quarter.

In the previous 11 quarters, we only dropped out of that range once, and that was the back-end of last year.

So for us that's pretty sustainable, because that means we sustain that performance through the ups and downs of the market in a very strong way.

And particularly over the past year or so we've definitely seen the strength of the business in terms of the changes to the business model that we've been making, reducing our costs, and certainly our ability to retain or work the power of the brand in markets such as the US where we're actually increasing our market share in retail and in lubricants.

Our lubricants global market share is now a clear number one.

We have extended that to around 14% while most major global competitors have been moving in the other direction.

A lot of it has been from emerging market growth in China and Russia.

And so markets in lubricants are B-to-B retail -- our B-to-B lubricants and trading business very strong, as far as we're concerned.

Looks very sustainable in the market environment despite the fact that one or two market as a whole are down a bit.

In terms of total demand.

Exploration program.

We are in the process of the first wells on the BMS-54 block.

This is now 80% Shell, 20% [Totale].

[Totale] just found in.

This is an attractive block in the Santos basin pre-sold.

We have two exploration well plans.

Each well will test to horizons.

We're in the middle of the first well.

We've been through the first horizon.

Some encouraging oil shales in the first of the two targets.

We're now looking at the logs and drilling ahead into the second horizon.

We'd expect to spud the second well, which is completely independent prospect in the same block, independent geologically, that is.

And that we hope to spud in the early part of 2011.

So essentially four horizons targeted.

First one, encouraging oil shales.

Too early to really say how big the find may be.

Thank you.

Move on to the next question.

Thanks, Michele.

Thank you.

Our next question comes Theepan Jothilingam from Morgan Stanley.

Please go ahead with your question.

Afternoon, Simon.

Afternoon to you.

Two questions.

Firstly just on international gas pricing.

Continued to see an improvement there.

I was wondering if you could talk about how you see pricing into Q4?

Are we at the end of the benefit from the oil price lag or not?

Perhaps a little bit of color on how you see demand for international gas today.

Second question was just where you saw underlying depreciation would be for the group both for 2010 and 2011?

Thanks.

Thanks, Theepan.

International gas pricing in general, two different markets really, Europe and Asia.

In Q3 we saw 55% of the European volume was spot price or spot price-linked That's higher historically would be more at the 40% level.

That's a trend we've been seeing anyway I think you'll appreciate over recent years or recent quarters.

That has some impact in reducing the premium that we typically achieved above, for example, the UK NBP.

In demand terms, demand for our gases held up reasonably well.

We have put some LNG into Europe, but from Nigeria, for example, but most of our LNG, the margin is going into the Asian markets.

We've seen very strong demand and good spot prices in Asia, particularly in Japan and Korea, but we've also seen volumes -- putting volumes into the Middle East, into Kuwait.

We've got volumes for demand in from India.

There's quite a few other markets, Singapore, Thailand, beginning to look for shorter term suppliers.

They do their own (inaudible) facilities.

So the Asian market, relatively attractive.

European market clearly depends on the weather., always does.

So far we've been relatively warm.

The comparative quarter, one year ago it was a very warm quarter, but we then were followed by a very cold quarter in the first quarter 2010.

So you need to watch that for both demand across and the margin, the price will also follow the demand.

The second question was --

Just on underlying depreciation.

Depreciation.

Sorry, it's a bit noisy this quarter for the impact of the impairments, but fundamentally the total group level is just under $3 billion, I would say, which is slightly lower than it was a year ago, partly because of reserved bookings at the end of 2010.

That's about $2.1 billion in the upstream, $800 million in the downstream.

So that's about the ongoing rate, if that helps.

Great.

Move on to the next question.

Thank you.

Thank you.

Our next question comes from Simon Hawkins from Ambrian Partners.

Please go ahead.

Afternoon, Simon.

Just a couple of questions.

One, just on acquisitions and just where they're going.

You're acquiring biofuels, coal seam gas, oil sands, and getting rid of stat fuel and Nigerian licenses.

Does this signal move to a more unconventional business field growth, or is it just part of the general thrust for energy, or what's really causing the move towards those?

And the second thing was, reserves impact of the Nigerian divestment program, are you able to give any color on that right now, either on what you've just divested or ones that you are going to be divesting for the whole program?

Thank you.

Thanks, Simon.

And I'll start with Nigeria first.

The reserve impact of the licenses that we've divested, the four licenses so far, is very minimal.

We've got very low reserves booked.

The resources or potential resources is a bit higher because the blocks are resource-rich, reserve-poor, so to speak -- pretty much undeveloped.

One of the main drivers of the strategy is in fact we have 30 licenses, probably more than we can develop, given that the Nigerian financing is limited, and we'd like to focus that on the areas of greatest strategic interest.

Supply of gas to nigeria LNG in the domestic gas situation and some of the core oil position.

So impact on reserves is very minimal.

That is linked to the first question, the acquisition divestment strategy.

We've always said we'd find it -- last several years, we'd find it difficult to see value in larger acquisitions for Shell, where we can create value in the typically in bolt-on niche play acquisitions where we acquire relatively undeveloped assets.

That's the common theme rather than any piece of technology, if you look at that time biofuels, the coal-bed methane and the Shell gas that we've acquired over the past two to three years.

We tend or try not to think of assets as conventional or unconventional, primarily because what is unconventional today becomes conventional tomorrow.

It's very much part of our strategy to select assets where we think we can compete, either lower cost or creating greater value from those assets, and each of the acquisitions matches that.

Conversely, the divestments are in areas where we either see limited growth potential or we see other people may be more prepared to invest or we could create more value, whether it's in Nigeria or Norway.

So typically mature assets are ones that are not likely to meet our investment criteria of those that we're divesting.

Hopefully that helps.

Thanks a lot, Simon.

That's great.

Move on.

Next question comes from Jon Rigby from UBS.

Please proceed with your question.

Hi, Simon.

Good afternoon, Jon.

Two quick questions.

One is to go back to the downstream.

I take your point about marketing but it seems to me the impressive number actually was your refining earnings compared to what's been happening in the last five, six quarters.

I'm struggling to triangulate your performance against your refining margins now.

I just wondered whether you could characterize what that performance looked like against your expectations this quarter, and maybe give some commentary on the moving parts, maybe sequentially and year-over-year ex refining margin, so I can get a better idea about how underlying performance is moving.

The second is just on your upstream.

Any update on thoughts about when you can start or when you hope to start drilling either Appomattox and around there in the Gulf and also the Alaskan/Northern Canadian stuff that you've got.

Thanks, Jon.

Refining triangulation, I wish it were that easy.

You're right, the third quarter, the loss of only $100 million was slightly better than you might have expected from the trends in the industry margins.

By and large we had good availability and lower costs in the quarter.

But one factor that we also benefited from was that when you see quite some volatility in the last two to three weeks of the quarter on the foreign exchange rate and on the commodity prices which in essence you did as the oil prices went from the low $70s to the low $80s.

You can get one or two one-off effects that benefit refining.

So there was an effect difficult to quantify but it helped Q3 relative to Q2 and will not repeat.

What is important is that we've completed or at least agreed the sale of two refineries, Heide and Gothenburg, in Sweden.

We continue the process on Hallberg and Stanlow.

Ultimately, focusing our portfolio and also our investment on a smaller number but a higher average quality of refinery is where we will see the benefit over time.

And thanks for the question on the upstream, particularly the impact of the moratorium.

I'm not sure how you knew this but, yes, Appomattox is quite top of our list for when resumption of drilling is possible.

The moratorium was lifted recently.

We -- you will hopefully be aware that we -- as the new regulations have come out, as we've seen the facts emerge from the oil spill incident, we've looked at our own design standards.

We've looked at our own operations processes, and we have a couple of minor tweaks.

We believe they are pretty much fit for purpose going forward.

We do have rigs.

We do have equipment that meet the required standards.

As soon as the moratorium was lifted, we put in requests to drill across a different -- a diverse set of opportunities so we've got workover requests, development wells, and the Appomattox appraisal well that are all now in the queue waiting for consideration by the new regulator.

Typically in the past these took an average 30 days.

We might expect it will take a little bit longer than that this time.

We, of course, have no idea how long it might be.

We are well aware that not only is there the mid-term election, but the Presidential Commission is due to report out sometime in January.

That may have further requirements or changes in the guidelines, although I have to say we're encouraged by comments coming out of the conference, the international regulators all together in Vancouver, and it sounds like there's a very constructive discussion taking place there, and the comments made not just by the US regulators, but other regulators, give us some confidence that we will have a good workable system that is better for all parties there.

So we would not be surprised if it takes longer than 30 days, and that there will be some waiting to see what the outcome of the presidential commission would be.

As soon as we're allowed to drill, we will.

Alaska, of course, closely linked to that, we have the two opportunities, the Beaufort Sea, which is actually on the US side of the Beaufort and the Chukchi Sea.

We have already submitted applications to drill for next year for the Beaufort.

We have not submitted application for the Chukchi and we're not likely to until we see what the progress is on the Beaufort side.

We've not really entered into much dialogue since the submission of the application.

We wait to see what the response is there.

That we expect it to be closely linked to the Gulf.

Hopefully that helps.

Yes, that's great.

Thanks, Jon.

Thank you.

Our next question comes from Lucy Haskin from Barclays Capital.

Please go ahead with your question.

Afternoon, Simon.

Could I ask, you're talking about the divestment program focusing on mature producing capacity.

You've talked about slightly lower volumes possibly coming from the Gulf next year.

Given that most of the acquisitions you're putting in place won't be delivering on the 2012 time line, what contingency have you built into your guidance for that year in terms of volumes?

Thank you, Lucy.

The divestment program does take down some barrels at the margin.

The Gulf, just to repeat, at 40,000 barrels a day for 2011.

We don't know how much for 2012 because it will depend on how quickly we get back to drilling.

We did always say in 2012, 3.5 million barrels.

It's effectively pre-asset sales, but at that time it was also pre-acquisition of East Resources.

So we do manage the portfolio at the margin.

We need the cash flow target in 2012.

That's a target that is linked to the financial strategy and the requirement to be able to finance the dividend and the investment program.

The volume, 3.5 million, we expect to be able to deliver.

We expect to be able to target the investment in the areas that will help deliver that, and if there are to be more significant impacts from the Gulf or elsewhere, then we would update the market as soon as we see it.

But at the moment, we're committed to the 3.5 million.

Okay?

Thank you.

Thanks, Lucy.

Move on.

Thank you.

Our next question comes from Mark Gilman from Benchmark.

Please go ahead with your question.

Simon, good afternoon.

The tax rate in the quarter was exceedingly low, about 34%, if my math is right, which is surprising, given the increase in Nigerian volumes.

Could you address that and also comment on the extent to which you took any tax shelter associated with the impairments that you discussed?

I also have a follow-up.

I'll make that three questions.

Okay.

The tax rate, yes, it's lower.

There are quite a few one-off effects.

They don't impact the underlying normal rate, the 45%.

Extra Nigerian production, that's small vignette.

You may recall -- in fact, I recall you asking questions about our financing arrangements where we looked to support the Nigerian government's share of projects, [Barnubie], Nembe Creek trunk line, and we also helped advance the offshore EA platform.

The actual return on that financing comes through a tax credit, and you are seeing some of that in the quarter.

So the effective tax rate in Nigeria at the moment while we're repaying that financing, which, in total, come close to $2 billion, Shell's share.

We're seeing the benefits of that now.

So we took a risk.

We managed it well.

We're seeing the benefits now.

So there is a tax shelter on the impairment, and the one-off noise will go again.

That's a bigger effect in the quarter than any of the other issues.

What was the final question?

My follow-up relates to a comment that I picked out of the release, which I found I guess to be a little bit surprising.

Relating to the intent to rationalize your North American tight gas position.

Can you be a little bit more specific as to what your targets in that regard might be?

The clear strategy in the North American gas position is to upgrade the portfolio so that our average cost and revenue are on the acres that we own and operate is ahead of the competition.

We took on new acreage in the Eagle Ford and Marcellus earlier this year.

The deal we did with the guys who run these deals and the assets in North America was, yes, you can acquire at the margin there, but you must divest some of the bottom end of the acreage, the less attractive acreage in order to at least partially finance the acquisition.

What we have spoken about, and I think we mentioned in this our recent investor trip to Canada is that the south Texas assets are potentially to be marketed.

And there are other smaller, more marginal assets that we might look to monetize in order to focus the investment that we do make on the areas of lowest cost and greatest proximity to market.

Hope that covers that.

If I can sneak in one more, how do make money on the Kidan sour gas field in Saudi should you choose to proceed with commercial development?

For those who are not familiar with that, the Kidan sour gas field is part of the long-term relationship, exploration program we have with Saudi Aramco.

The straight answer is we don't yet have commercial terms so we don't know how we make money but we can also say there's a lot of gas there, there is a definite need for gas in the region, and we have a very good relationship with Saudi Aramco.

So we're very aligned.

How we actually monetize it is still to be negotiated.

Thank you, Simon.

Thank you, move on.

Thank you.

Our next question comes from Alejandro Demichelis from Bank of America.

Please proceed with your question.

Yes, good afternoon, Simon.

Couple of questions.

Just to clarify on the production that you were talking about, clearly 2012 you are going to be under 3.5 million, but can we see 2011 being a down year over 2010?

That's one question.

The second question is in terms of the CapEx going forward, can you tell us roughly how you see this for the fourth quarter and 2011 as well?

Thanks, Alejandro.

Yes, I can see the reason for question on production as we're probably over-performing in 2010.

3.15 million barrels a day last year, we're about 5% up year-to-date.

We did say we expected to be roughly flat this year, probably can't continue to say we expected the roughly flat, but I would point out that we've had one or two positive factors this year.

I mentioned a very cold first quarter.

Our Nigerian production, we've had those good projects have come on stream, but essentially the security situation has improved as well.

So our underlying production from the new projects coming on overall is a couple of percentage points up but not all of the 5% that we see.

2011 always was a ramp-up year.

We've got, I mentioned oil sands.

We'll see hopefully the deepwater ramp-up in Perdido but most important of all, [Qatar].

By the end of the year we hope to be at or close to full production, which is 7% or 8% over 300,000 barrels a day.

We can't predict exactly the monthly ramp-up rate.

Clearly if we're successful, we will have quite a healthy growth during the year.

If it takes a few extra months, the growth rate will be lower.

But overall, 2011 was a ramp-up year between the 2009 and 2010 base, and the 2012 growth target.

I would expect by and large for it to be up, but how far up it will be driven by the rate of progress in the ramp-ups with Qatar in particular.

On the CapEx, we've said, and we'll stick with $25 billion to $30 billion per year of organic CapEx, offset by divestments to the extent we expect the net CapEx to be $25 billion to $27 billion per year.

Next year, given the opportunity to drill in the Gulf of Mexico, also potentially in Alaska, we'd hope probably to be towards the top end of the organic range, but if we deliver our $7 billion to $8 billion of divestments we'll also be towards the top end of the range there.

So the net should be in that $25 billion to 27 billion range.

I can't say any more than that, because we haven't yet finalized the capital feeling for the years and we stick with the $25 billion to $30 billion going forward.

I will just note, by the time we get to 2012, 2013, if we're going forward with the major Iraq project, that, that will have an impact.

That was always outside the $25 billion to $30 billion range, depending on the pace and the size of the major build-up in Iraq.

That's very clear.

Thank you.

Thank you.

Our next question comes from Paul Andriessen from ABN AMRO.

Please proceed with your question.

Hello Simon.

A question on Pearl, the GTL project, what's the current status of completion and what quarter of next year do you expect the first volumes?

Thanks, Paul.

No real news to update.

They -- we expect volumes in the second quarter -- by the end of the second quarter which would enable us to recognize the revenues from the condensate during the quarter.

The status of the project, we are in middle stages of commissioning of the first train.

The second train is about six months behind.

Always was, planned behind the first train, and we look to apply the learnings from the first train to the second train.

We had a slow start on the steam blow, which is actually making sure everything is joined up, all the pipes are joined to the right pipe and that they actually retain the pressure designed for, but we're catching up on that now, and working pretty quickly through that program.

So still on track for delivery in terms of GTL by the second quarter.

We will update as and when we achieve important milestones, or there's any change to that schedule.

Okay.

Thank you.

Thank you very much.

Thank you.

Our next question comes from Jason Kenney from ING.

Hi, Simon.

Getting back to Iraq, can you update us on the potential natural gas contract there?

I think it's on the near term horizon at least.

I mean, you mentioned the potential higher CapEx.

What CapEx level are we looking at, should you be including in that project?

I was just wondering -- I noted a couple comments earlier today, you said your dividend is already competitive.

I get a feeling you're down playing any future growth in the dividend.

I'm wondering if you're more encouraged to consider shopping debt for equity and perhaps restarting share buybacks in preference to growing the dividend in the near term or medium term.

Thanks, Jason.

You're right, quite a few comments in the press recently about the SAS gas opportunity.

Just to recap, we're a non-operating partner with Exxon in West Qurna.

We operate the Majnoon oil development, and the SAS gas development is in essence a project to capture associated gas from the fields that are being developed into the international licenses.

Briefly, West Qurna and Majnoon are going forward.

We're quickly drilling in West Qurna Majnoon, we're working on the early production system.

For the SAS gas, we have been in negotiations for quite some time.

The actual proposal has been supported at various levels of the Iraqi government, but we're still waiting for final sign-up.

It's not easy to find -- to quite identify exactly who needs to sign off at what point, so the progress is always positive, but we're never quite sure where the final hurdle might be.

CapEx, the first part of the CapEx is relatively low.

It's essentially facilitates to capture gas that's already been put together.

Over time, though, we will move first of all to capturing and stripping the LPG and potentially exporting LPG, and then finally, if there is excess gas beyond the domestic gas requirements, there is potential for LNG export from the country.

That is -- there are effectively three distinct phases or potential phases of investment.

So the upfront CapEx is relatively low.

We'll update as soon as we know what we've actually agreed with the government there.

Dividend.

Complex issue.

Just to reframe this maybe, we reset the dividend policy back in March.

We moved away from an inflation linked, almost an index linked dividend, beating the index typically historically to where -- policy where we would more like to closely link the dividend with the underlying earnings and cash flow of the Company.

We are well aware of the importance of the dividend to the shareholder.

It's been increasingly clear over the past year or so that there are two camps in our investors, now shareholders.

Most investors fall in one or the other, quite clearly, quite polarized.

Either they want an increase in the dividend, or they encourage to us go the other way and to reinvest on the grounds that most of our investments will deliver a return considerably above the cost of capital.

So quite some debate.

We have left the dividend at the constant level for the last 18 months.

We have not changed it today.

We don't currently have plans to change it.

We are the highest single dividend payer in the FTSE by quite some way now.

Four of our European competitors have cut dividend this year.

And our payout ratio and dividend yield are considerably higher than our American competitors.

Therefore, we think our dividend is extraordinarily competitive at this point in time.

We would like to see the earnings and the cash generation grow to the point where our payout ratio is maybe a little less competitive.

We are -- In 2009 we paid out pretty much all of our earnings in dividend and this year it's still over 50% year-to-date.

So that's a pretty high payout ratio.

I'd like to see that more balanced in line with the competition.

Okay, move on to the next question.

Next question comes from Jack [Moore] from [Hartford] Capital.

Please proceed with your question.

Good afternoon.

Good afternoon, Jack.

I was wondering if you could comment on natural gas in North America specifically, just the recent transactions with people farming in on acreage and what your thoughts are there?

And then also just the notion that a lot of production is being -- a lot of drilling is being done to hold acres, and where you see gas over the next 18 months or so going, and how you expect to react to that?

Thanks, Jack.

Very important question for us.

Our strategy has been to take large acreage positions through either acquisition of companies or assets or direct purchase of the acreage.

We're now present in eight basins.

We believe we've got strong positions in each of the prime basins in the country, whether Marcellus, Haynesville, Pinedale, or up in Canada, western Canada and British Columbia.

A strong position.

We do not think that farming in to somebody else's acreage for a minority share as a non-operator is really aligned with our own business model.

It would not create value for our shareholders.

We've also -- I would recognize that we do believe a lot of drilling in the past 12 months, and maybe for the next 6 months to 12 months has been driven by the need to hold acreage, particularly in the Haynesville area, but also some of the other basins, and some of that drilling may well not have been very economic.

Against that many companies have hedged their production, which made it just about economic, but those hedges are now beginning to run out.

So we see -- it was always our premise that by the end of 2012 a lot of that drilling to hold acreage by production would have reduced that, the hedges would have run out, and the supply demand position would move the price more to the marginal cost, which we think is a bit higher than the gas prices to-date.

We've seen, interestingly, in the last few day, few announcements which suggest we might have been right on that.

So we do think that supply and demand will begin to reassert themselves over the next 12 months to 18 months, and that prices will move to levels which will make our acreage where we believe we're heading for unit cost, lowest unit cost in each of the basins, it will make our acreage look pretty attractive and the returns equally attractive.

We have said previously we could spend between $2 billion and $4 billion a year on this activity ourselves.

The new acreage might enable to us spend $3 billion and $5 billion.

This year will be somewhere between $2.5 billion and $3 billion, so we are at that lower end of the range of ongoing investment activity, and we'll see how the markets develop before we agree the level of spending for next year.

So hopefully that's given you the context and where we are in the strategy.

Thank you.

Thanks, Simon.

We'll move on to the next question.

(Operator Instructions) We have a follow-up question from Mark Gilman from benchmark Company.

Please proceed with your question.

Simon, if my math is right and the full-year 2010 is going to hit the low end of your organic range, we seem to be looking at organic fourth quarter capital expenditures somewhere in the $9 billion plus range.

Is that what we should be anticipating?

I'm not sure I can give you an exact projection but it will be more on average of the first three quarters.

It always is.

Perhaps a little bit more disciplined over the value of work and accruals and other such issues.

It will be up, but not that material.

So let's see where it comes out.

Great.

If I could just ask to you clarify something that -- your comment you made earlier, your $800 million to $1.2 billion per quarter range in your discussion of the downstream, was that a trading contribution or the overall marketing contribution?

Marketing and trading in the downstream.

Excluding chemicals.

Chemicals is shown separately.

Thank you.

Thanks, Mark.

And I think we've got one question.

One more question to come.

Thank you.

Our final question comes from Bert van Hoogenhuyze from De Vries & Co.

Hi, Simon.

I came in a little late so maybe it has been asked, but I was just wondering, regarding your remarks about Chukchi.

Is there any obligation to drill before a certain year?

Does this agree with your license?

And maybe that in respect also, I saw one or two days ago that US service had reduced its estimates of Alaska reserves by about 10%.

Does this tally with your view as well?

Thanks, Bert.

All US licenses after ten-year life cycle.

We took the licenses in Chukchi in 2007.

The moratorium, they actually agreed to stop the clock on the ten years.

So we do have a bit of extra time.

Given some of the challenges we've had, probably negotiation, at which time we have, but we really need to wait and see what happens with the Beaufort application.

And overall views on Alaskan reserves seem to vary hugely depending on whether you're American, Russian, Canadian, or Norwegian.

Our expectations for the Beaufort and the Chukchi have not changed.

We drilled both acreages in the back end of the 1980s and the early 1990s.

So we've gone back over our own results.

We've gone -- shot new seismic.

We're very confident that we've got some good prospects there, and we really look forward to drilling them.

Great.

One final follow-up, if I may.

You have, of course, your joint venture in Sichuan, China for the shale gas.

I saw that recently the Chinese have decided to give more licenses to the domestic operators.

Is your view that this is a one-only involving a foreign Company like Shell, or do you see chances for further licenses there?

Yes, you're right, in Sichuan, we have two 4,000-square kilometer licenses for production sharing contracts with PetroChina.

We also got the coal-bed methane licenses elsewhere and we're working on further acreage with PetroChina.

China is a big country.

8,000 square kilometers may sound a lot, but perhaps more so in the Netherlands than China.

There is a lot of potential.

Ultimately access for foreign players will be driven by the quality of relationships with Chinese companies.

There is no way that foreigners will be allowed direct access anyway.

That's always been the cause from our perspective.

But we've been successful in negotiating opportunities, partly because we're working outside China with our Chinese partners as well.

And we would hope there is further potential for that in future.

One thing we're saying is that we have actually got the rigs in place.

We expect to drill in the next two months to three months in both of those acreages and start to understand just what the potential really might be within China.

Great.

Thanks, Bert.

That's very helpful.

We do have one more question there, thanks.

I will take that one, operator.

Thank you.

The last question does come Emmanuel Owusu-Darkwa from Barclays Capital.

Please proceed with your question.

Thanks.

Hi, gents, thanks for taking my question.

Just a couple.

Where do you see gearing at year end, and secondly, what are your plans for disposal proceeds with respect to you expect to receive in the next year or so?

The first question about year end, what was that?

Gearing.

Gearing, thank you.

We came from 17% through 19% in the quarter.

We'd expect most like toll increase slightly to around 20% in the fourth quarter.

That's pretty much where we said it would be on the last quarterly call so pretty much to plan.

Divestment proceeds, in the first instance they are keeping that gearing ratio down.

One unknown factor for us in this particular quarter is what rate of take-up of the script dividend.

That's something we cannot predict and we will now in a few weeks time.

And the -- just to reiterate as well, $7 billion to $8 billion of divestment income or proceeds over the next two years.

If our cash flow ramps up to being effectively self-sufficient at $60 in 2012, the $7 billion to $8 billion will be used to keep gearing in the right range or a comfortable range.

Or you could look at it from a different perspective, as if it's being used to reinvest.

But either way it will be applied primarily to keep gearing in the right range.

So hopefully that will help.

Thanks.

Thank you very much.

I think that's all we have time for, operator.

Thank you.

This does conclude the conference call for today.

You may now disconnect.