殼牌 (SHEL) 2010 Q4 法說會逐字稿

Please stand by for realtime transcript.

Welcome to the Royal Dutch Shell Q4 results announcement call.

There will be a presentation followed by a Q&A session.

I would like to introduce our first speaker, Mr Peter Voser.

Please go ahead, sir.

Thank you, Operator.

Good afternoon, everybody.

Simon and I will take you through the results and through the full developments for the fourth quarter, and specifically for the full year 2010.

I will have plenty of time for your questions.

Firstly, take a moment to read the disclaimer.

The world is in an era of important geopolitical transitions, strong volatility, and the intensified economic cycles.

Emerging nations like China and India are going through intensive developments.

The recession interrupted the oil and commodity price boom, but it may well return.

This is a complex and volatile landscape for the energy industry and an opportunity for Shell.

A year ago, I mapped out a three year plan for Shell to 2012.

The focus is on three key strategy priorities.

Improving our near term performance.

Growing the Company by bringing new projects on stream.

And generating new options for future growth.

I am pleased to say that we have made good progress on all of these themes in 2010.

Our 2010 CCS earnings, excluding identified items, was $18 billion and earnings per share increased of 56% year-on-year.

This improvement comes despite pressure on downstream margins and natural gas prices.

We have taken our $2 billion of costs and we sold $7 billion of non-core assets, which exits from 12% of our refining capacity.

We increased our upstream production by 5%.

We made eight new discoveries and made strategic acquisitions in unconventional gas and biofuels.

Project delivery is going well and I will update you on that, including Qatar, in a moment.

Overall good progress on our plans in 2010.

Let me say also, although we made good progress overall in 2010, I'm not satisfied with the fourth quarter results.

These results on the score why we have set out the three year plan for imbedded performance from Shell and we have more to do.

We have reduced underlying costs by $2 billion in 2010, bringing the total cost deduction for 2009 and 2010 to $4 billion or about 10%.

We haven't stopped here.

We have a series of continuous improvement programs on the way across the Company.

These plans in total are expected to deliver further multi-billion dollar cost savings in the near future.

By going forward, we should expect to see increases in headline costs in the areas where we are targeting growth.

However, our continuous improvement plans should go some way to offset these trends.

Now let me update you on our asset sales program.

2010 asset sales proceeds were $7 billion, essentially completing our 2010 and 2011 targets for $7 billion to $8 billion.

This includes exits from seven of our eight non-core refineries and continued progress in refocusing our marketing portfolio.

We have exited from 450,000 barrels per day of refining capacity in 2010, or about 12% of our total, and this brings the reductions in 2002 to almost 30%, or 1.2 million-barrels per day.

Total asset sales in the last five years were some $30 billion, which is a roll over of about 20% of our capital employed.

From here, the pace of asset sales could slow, although we expect some $5 billion for a 2011, including some $2 billion of proceeds still to come from these down across the ends of 2010.

Let me now turn to gross delivery.

We have a sequence of new projects for 2010 and 2011 start up that are underpin our production and cash flow targets for 2012.

We have made good progress in 2010 with six new startups.

Let me give you an example.

In Nigeria, the Gbaran Ubie cash project has ramped up well and is on track for its peak production of some 250,000 barrels of BOEs per day.

This adds to Nigeria's LNG supply capacity and will feed electricity supplies for local communities.

Now our most recent startup in early 2011 was in Qatar.

Let me say more about that with the next slide.

2011 is going to be an exciting year for Shell in Qatar.

We have two projects there, both due for start up this year, Pearl GTL and Qatargas 4 LNG.

Together, these projects, which will cost about $20 billion for Shell and add some 350,000 BOEs per day, to our production which is over 10% of our current production worldwide today.

The first of these, Qatargas 4 LNG is now in the start up phase.

We started to produce LNG at Qatargas 4 in the last few days and we are expecting the first shipment of LNG in the next few weeks.

Our second project in Qatar, Pearl GTL, is also making good progress.

Major construction on both strains is now complete.

This was a mammoth undertaking, 52,000 workers at the construction peak.

Safety performance has been excellent and we have set new records in 2010 with 77 million working hours or hours worked on shore without a loss time incident.

During the fourth quarter of 2010, we made continual progress in commissioning.

More than half of the roughly 2000 trained well systems we need have been brought to what we call ready for startup status.

We have completed our trained [vonsteen] blowing.

We have started our first air separation unit.

Imported gas, oil, and condensate to do the live commissioning and load the catalyst in over half of our train [von] reactors.

So, overall a very satisfactory performance for what is a lot and complex facility.

Now let me update you on progress with longer term options.

We are working hard to turn exploration success into commercial production.

In 2010, we took [final rest] position on two new deep water projects in the Gulf of Mexico and Brazil.

And we have made good progress with new exploration and appraisal with eight new finds and further plays of success.

Now we are starting all of these results and will update you on the resource potential during our strategy presentation in March, like in previous years.

2010 was also a busy year for new deals.

We have had the new acreage positions in 2010 some 53,000 square kilometers.

The focus here has been on building up new place for Shell.

We have also made progress on Iraq oil, and in our downstream and biofuels joint venture in Brazil.

Shell has a long history of successful partnerships with national oil companies.

I would like to highlight the new momentum that we have built with (inaudible) in 2010, including deals with Petronas in Iraq, in Qatar where we are in talks for a new petrochemicals plant.

In Saudi Arabia going forward in the energy quarter.

And there's China.

We have concluded a series of deals with the Chinese NOCs in 2010.

This included an upstream partnership in Syria.

The joint acquisition of Arrow.

The CBM LNG playing in Australia.

Gas exploration in China and exploration in Qatar linking Shell QP and Chinese NOC.

Finally on NOC, late last year we signed a new MOU with Gazprom looking at joint expansion of our upstream activities in Russia.

So, Sakhalin invests in Salym in West Siberia are the new international partnership.

Before I hand you over to Simon, let me say a few words about safety.

Safety is at the heart of everything that we do here at Shell.

We managed personal and process safety with the positive trend you can see on this chart.

Macondo, the largest ever deep water blowout and the largest peace time oil spill for 100 years.

We can all talk about causes and make all kinds of explanations.

But the reality that is the picture has changed for the deep water industry.

There will be increased regulations and more public scrutiny and safety.

To put it simply, our industry needs to rebuild trust with the communities we work in.

Shell has a good track record in deep water and we always look for ways to improve.

We have completed an initial review of the presidential commission report into Macondo and we agree with the majority of the findings.

In particular, we shared a conclusion that the US regulations and the risk management practices of some companies in the Gulf of Mexico do lag behind the standards set by other companies, and set by regulators in other countries.

We support the commission's recommendation to introduce risk based standards specific to their relevant activities.

Similar to the safety case approach in the North Sea.

We at Shell have been applying the best of the North Sea standards to our worldwide operations for many years.

This includes the safety case approach worldwide.

On Shell's wells the roles and responsibilities are clear.

Both for accident prevention and incident response and we have a strong safety record.

Let me also update you on the near term ratings outlook in the US offshore.

In the Gulf, I'm pleased to say that Shell is the first company to have successfully submit the plans for exploration drilling, three wells in the Auger area in accordance with the new agency standards for the Gulf.

These permits are now with the authorities for review.

In Alaska, Shell has the leading acreage position in offshore Alaska and this remains an interesting area for us in the longer term.

We have been working rigorously for the past five years to meet and exceed all regulatory and permitting requirements in Alaska.

However, despite our investment in acreage and technology and our work with [state cause], we have not been able to drill a single exploration well.

Our plan for drilling in 2010 were put on hold following the BP Macondo blowout.

Despite our best efforts, critical permits continue to be delayed and the time line for getting these permits is still uncertain.

Therefore, regrettably because of these uncertainties, we have decided not to drill in offshore Alaska in 2012 and stop the spending for these activities.

We need urgent and timely actions on permitting and regulations in order to go ahead with 2012 drilling to 2012 drilling program, we are working towards that.

With that, I pass you to Simon on the results .

Many thanks, Peter.

I will just take you through the fourth quarter numbers and give you a heads up on some of the key figures for 2011.

First, on the macro, if you look at the macro picture compared with the fourth quarter of 2009, the oil and gas prices have increased from a year ago levels, although in North America the gas prices did decline.

Refining margins increased from a year ago levels and chemicals margins increased in the United States, but they declined slightly in the other regions.

Turning now to Shell's fourth quarter earnings, the headline current cost of supply earnings are $5.7 billion for the quarter, they include identified items of $1.6 billion, primarily gains on asset sales, mainly Woodside.

Excluding the identified items, the CCS earnings were $4.1 billion and that's an earnings per share increase from Q4 2009 of 49%.

Cash flow from operations for the quarter was $5.5 billion.

And the dividend for the fourth quarter was announced at $0.42 per share.

And we expect to announce the first quarter 2011 dividends as an unchanged $0.42 per share, although, this of course is a decision reserved for the Board at a later date.

In the third quarter, we introduced the script dividend for the first time, the take up of the script was equivalent to around $600 million.

And that is a about a quarter of the dividend, and we are offering the script, again of course, for the fourth quarter.

Now let me turn to the business performance in a bit more detail.

Firstly the upstream, excluding the identified items the upstream earnings increased by 25% to $3.4 billion in Q4.

And that was driven primarily by higher oil prices, higher realized gas prices outside of North America, and by the 5% increase volumes.

We did see increased costs in some areas associated with, for example start up activities in projects such as Canada, oil sands in Qatar and in Iraq.

Of course, we are building up that operating capability ahead of the new revenue and production growth that we expect when the projects come on stream.

We had, overall, another good quarter for production.

The upstream production increased by around 5%, Q4 on Q4.

And LNG sales volumes increased by 11% for the quarter.

If you look at the full year, the production operates to 3.3 million barrels of oil equivalent per day, airport from the new fill and fill ramp-ups was 170,000 barrels of oil equivalent per day and that more than offset the natural fill decline.

Production this year was almost boosted by external factors such as colder weather, particularly in Europe and North America, an improved security situation in Nigeria.

And [ample] production was ahead of our original guidance for the year and having said that, the growth was typically from lower margin barrels.

For the full year the LNG sales volumes grew by 25%.

That was underpinned by increased volumes in Nigeria, LNG, largely increased supplies from new projects and better security, but also by the full ramp-up of Sakhalin LNG in Russia, which has been producing above name plate capacity for basically all of 2010.

Turning to the US upstream where the whole of our industry of course is being impacted by the BP Macondo blowout.

Peter talked about the longer term implications and I will focus on the financial impact.

So, we didn't actually receive any permits for new exploration or development drilling during Q4.

As a result, we took a $70 million identified charge in the fourth quarter for the cost of the idled rigs, four deep water floaters that we have in the region.

This combined with the charges in the earlier quarters, Q2 and Q3, and the production shortfalls that led to an earnings loss for Shell in the full year of $260 million.

Equivalent was 10,000 barrels of oil equivalent a day of lost high value production, mainly liquids.

By the year end, that was a run rate approaching 30,000 of barrels of oil equivalent a day.

And we actually had to postpone around $700 million of planned investment in exploration and development during the year.

2011, we are expecting around a 50,000-barrel a day impact against the plans that we had prior to the moratorium and that's an increase in the guidance of the last previous we had around 40,000.

Recognizing that the slow pace of any likely restart in the Gulf and the lack of any permits being issued to date.

Turning now to the downstream.

Excluding the identified items, the downstream CCS earnings increased from the fourth quarter 2009 at around $482 million.

Within this number the chemicals earnings increased substantially.

This is driven by industry margins, lower costs and our actions to enhance the portfolio to improve the structure of the margins, including conversion to gas feed.

And chemicals margins did fall at the end of the quarter reflecting higher naphtha prices following the crude price up.

And that will impact on into the first quarter of 2011.

I should also update you that we have substantial planned downtime in the Singapore chemicals plant in the first quarter of 2011.

Both factors will play a part.

In refining we did see an improvement in the industry refining margins and certainly year on year improved outcome.

But, the refining conditions do remain difficult overall.

Reflected, of course, in the losses in refining in the quarter which were around $460 million.

That compares with losses around $940 million last year in the fourth quarter.

And then also impacted by exchange rate movements and refinery downtime.

We had maintenance downtime, planned and unplanned, including cat crackers, cat crackers being the main revenue generator in several of our refineries and we had that downtime at eight refineries in the fourth quarter.

It's also typical that we concentrate or focus our maintenance activities in Q4 and in Q1, which is typically higher -- a lower demand quarter.

The increased costs associated with the additional maintenance and the opportunity lost, the margin lost as a result of not operating, that cost us around $200 million in the fourth quarter.

For the first quarter of 2011, we are expecting similar or even slightly lower refinery availability compared with Q4, 2010.

Again, impact on Q1 results.

The [masking] earnings were broadly similar to a year ago.

But after a year ago and in Q4 this is below the long term trend.

Several hundred million dollars below marketing and trading results of the quarter were around $375 million.

We did see lower costs and we did better year on year in retail lubricants and B2B.

But trading overall, so a less favorable environment and less positive contribution.

Mostly margins and underline volumes did decline compared to the third quarter of 2010, and that was mostly driven by the steady increase in oil prices, although it was also impacted by some of the weather conditions we saw in the US and Europe.

So, those are the earnings.

Turn now to the cash flow.

Cash generation on a rolling basis, the 12 month basis was around $40 billion.

Including $7 billion of disposal proceeds.

Also excluding the working capital impacted CFFO.

And that was broadly balanced against the outflow of $39 billion for the year.

Upstream and downstream businesses cash generation was in fact ahead of the our own spending requirements.

We remain, have been, and will remain in a capital intensive stage as we invest for the new growth.

We continue to watch the cash position and the balance sheet very closely.

Particular emphasis on cost and, of course, capital efficiency.

As I turn to CapEx in the balance sheet, we ended the year 2010 with gearing at 17.1%.

That's several percentage points below earlier projections.

Slightly down from the third quarter levels.

Comfortably in the target range of zero to 30%.

Helped, of course, by divestments concluded in the quarter.

Our return on capital in service at IE currently producing assets was 18.5%.

Of course, that is only about two-thirds of the balance sheet.

About 65% at the moment.

Rest of the balance sheet remains work in progress and to produce in the future.

2010, was also a busy year for acquisitions.

$7 billion of acquisitions, not yet including the conclusion of around $2 billion of the Cosan joint venture in Brazil which should close in the coming months.

Those acquisitions were matched by an equivalent number $7 billion of asset sales.

Both of these additions and divestments part of the drive to enhance the portfolio, upgrade the quality of the margin and to improve the capital efficiency.

For 2011, we are expecting, in line with earlier strategic statements, net capital investment, $25 billion to $27 billion, in line with that long term strategic plan we talked about a year ago.

And you can see some of the details on this chart.

In 2011, we will see spending rates decreasing in some of the plays like Qatar and Canada heavy oil that have dominated recent spending, but we will step up in areas such as Australia, Iraq and, of course, the $2 billion to complete the Brazilian biofuels deal.

So, within this mix, I expect exploration spending of around $3 billion again this year.

And our overall North American tight gas spending where you will recall we talked about quite a wide range of possible spend.

We expect that to be around $3 billion again this year, so both exploration and the tight gas spending of around $3 billion.

Similar to 2010 levels, excluding acquisitions, of course, because around $6 billion of last year's acquisitions were actually in that area.

With that, let me pass you back to Peter to summarize before we move to the Q&A.

Thanks, Simon.

Just a quick summary from my side.

Our performance in 2010 on the lines that we are delivering on our strategy.

We are making good progress with our three strategic themes and targets for 2012.

Our earnings increased by 56% year on year, $2 billion of costs we took out, sold $7 billion of non-core assets.

Which exits from 12% of our refining capacity.

We increased our upstream production by 5%.

Made new discoveries and made strategic acquisitions in unconventional gas and biofuels.

Overall, good progress on our plans in 2010.

And Shell is back on track for growth.

Thank you very much.

Back to the operator for the Q&A session.

Thank you, sir.

We will now begin the question and answer session.

(Operator Instructions)The first question comes from Lucy Haskins from Barclays Capital.

Good afternoon.

I think at the first half stage you were then 12% of your 2012 sort of cash target.

Now there seems to have been a move away from this in terms of the 4Q numbers.

Obviously, Simon, you talked about some issues impacted the quarter.

Is there anything else you'd like to draw our attention in terms of being not quite special items, but slightly one off or exceptional at this stage?

And then the second question was how did you manage to spend $4 billion less than you thought you would during the course of last year?

I think I'm going to pass this one off to Peter.

Thank you Peter.

Thank you, Lucy.

Just to reiterate the cash flow performance and targets.

In 2009 it was actually adjustable working capital of $24 billion cash generation.

That's the basis for the 50% and 80% growth targets at $60 or $80.

Adjustable working capital was 33 in 2010.

Coincidentally actually 2009 was roughly a $60 world and 2010 was roughly an $80 world, albeit with, in both cases, gas and refining margins below where we'd expect mid cycle to be.

That cash flow in any given quarter or half is impacted by working capitals.

I think you need to take that into account when looking at any short-term cash flow generations.

I think even making those adjustments though, which I would agree, we always strip the working capital movements out.

Certainly you seemed a lot closer to targets sort of in the mid year point.

Now perhaps annualizing the 4Q would be unfair, but even for the full year 2010 numbers you clearly you are a bit farther away than you were at the midpoint of the year.

I just wondered if there had been anything exceptional in the first half.

Or something exceptional in the second half that perhaps is tracking back.

Let me finish, Lucy.

I was going to get on to the question.

The impacts for the quarter.

Of course, the first half we were producing better in the Gulf of Mexico than we were in the second half.

So, some impact there.

(Inaudible) that we have left on the table.

Tax payments typically are back end loaded in the year.

That is always ongoing effect.

Those two effects definitely come through.

Q4, against previous quarters, I don't want to give you a very long shopping list, but here are some things to think about.

In the upstream around $450 million income impact from startup costs.

Higher taxes and royalties, and that's on the income statement, not just paid, and that's partly re-valuation of deferred tax assets in Brazil and also low contribution from gas trading.

The market is just less volatile.

Most of that in the upstream showed in UA.

It's $450 million there.

I talked about refining.

The operational impacts basically left $200 million on the table.

The DIE impact is another $200 million and marketing, of course, was coming in $400 million below the typical trading range of 800 to $1.1 billion that we have done in most quarters.

When I say DIE effect, it's effect is the foreign exchange movement.

When the euro strengthens we get a benefit.

When the euro weakens we get a negative and we have had very significant euro dollar impacts this year.

In fact, absolute impact of Q4 wasn't that big.

It's really the comparative impact that you see coming through.

It's positive in Q3, negative in Q2.

A year ago it was roughly neutral as well.

That does introduce volatility.

So, yes, there are in Q4 several impacts that all feed through to the cash flow and most of them, if not one off, they do not occur structurally every quarter in the same direction.

Hopefully that helps.

Second area, how did we manage to spend $4 billion less?

We go into the year with a $28 billion capital target.

Peter keeps, in his back pocket, a hold back to the $4 billion, which is the maximum flexibility that we had.

During the year, some of that was allocated directly toward the smaller acquisitions that we made.

The larger acquisitions were then effectively offset by the divestment increase.

The Gulf of Mexico saved us, in that sense, $700 million of investment, and you will be pleased to hear we have taken cost out.

We delivered a few projects early so there is a contribution from both cost takeout and projects starting up early.

We also chose not to do one of two things.

Overall, it all added up and our aim was to manage the net investment and the balance sheet accordingly.

And you can see the outcome hopefully in the results.

Many thanks.

Thanks.

Our next question.

Thank you.

The next question comes from Jon Rigby from UBS.

Yes, thank you.

I have three questions.

Hopefully, all three of them quick.

The first is, it's notable how little money you are making in North America at the moment.

And I guess some of that as you reference is Gulf of Mexico.

I noticed you are still going to spend another $3 billion in tight gas.

At what point do you start to reappraise that portfolio shift that you have been conducting?

The second is can you just hazard a guess at what you think normal circumstances your capital in-service would be?

Then the third is, a long time ago it always seemed to be that certainly a fourth quarter Shell had a lot more costs coming in.

I kind of worked on the assumption that the tight centralization that had come into the business and the new accounting systems et cetera would do away with that.

Can you just talk to how you can have fairly dramatic shifts in how your booking costs through a quarterly period, please?Thanks.

Thanks, Jon.

Good afternoon.

I will take number one and three and capital service I will leave to Simon.

Let me talk about North American first.

I think making money, you can talk about it in terms of earnings or you can talk about it in terms of cash.

Simon talked about special stuff in Q4.

And you have been with us obviously in North America, et cetera.

We are driving the operational performance and we are driving, actually quite clearly, our assets to top performance, excluding obviously in the Gulf of Mexico issues which we have had.

So, actually, if you take a cash view on this, the Americas, or UA actually performed rather well, substantially above the earnings as most of the hits which we have had were actually in non-cash items, et cetera.

So, I think the way we or I manage at the moment, UA is clearly on a cost basis, but also on a cash basis.

We obviously keep earnings in mind.

But that's really how we are driving it and I'm pleased the way they are performing on the gas side in terms of optimizing cash costs and costs in general.

I'm pleased with the progress on total costs related to the direction of the portfolio.

Have to say, obviously as we have AUSP start up across the first half of 2011.

So, we have the mine start up and the upgrade is still to come.

We had higher cost for that, but we didn't get the revenues that had, obviously quite clearly, an impact.

All in all, I think we were on the right track.

Measuring the cash earnings which are substantial and therefore I think I'm pleased with the progress so far.

Also we have in the UA, actually, the highest percentage of known productive assets given our acquisition drive and our investments over the last few years.

Is it actually higher than the rest of the group, so if you look at the returns, pure earnings returns, you need to take that into account as well.

On the cost side, I think we are improved, because indeed in the past this was a little bit of a problem of Shell with the centralization of the systems.

The way we actually monitor our monthly counts.

We have improved.

It's maybe not everywhere completely done, but we have improved considerably over the last two years.

I wouldn't say this is our biggest problem in Q4.

I think some the operational things that Simon has said were much more kind of on our minds when we looked at our results and where we always check that we have the right strategic initiatives in place to sort out a few things, which we still have to sort out.

Yes, it's a problem which we know.

It's a problem that we have worked on quite a bit and it's getting better.

We have not yet completely there.

Capital and service I'll pass on to Simon.

Thanks, Peter.There is some linkage between the questions as well.

The capital outer service at the year end, the balance sheet was $194 billion of capital employed, and $44 billion working progress projects ready to roll.

Hopefully in the next year or so.

More than half of that is in Qatar and Canada oil sands because the upgrade is not operational.

It will drop, clearly, as those three projects come on stream.

It will then go back up again as we continue to invest.

This is our business models and that number will not reduce to zero.

It probably will run at the level below 44.

More towards 30 maybe plus or minus, let's say, as it goes forward.

We also have around $19 billion, $20 billion of lease bonuses or acquisition premiums.

For example on east resources, lease bonuses and some of the acquisition premium we do amortize anyway and because it's in North America, that amortization before we actually produce, does impact the results.

There is an impact there, that drives earnings down, but has no cash flow impact in our Upstream America results.

That piece of capital becomes active as we bring the assets into production.

So, the piece in the gas, particularly the unconventional gas, as we develop and produce east resource acreage, for example, that will reduce and returns will increase.

Quite closely linked answer and I don't know where that $19 billion to $20 billion will go.

I hope we continue to acquire new acreage going forward as a similar level to that which we have done recently.

Okay, that's great.

Thank you.

Thanks.

Thank you, Jon.

Next question.

Thank you and the next question comes from [Allen Stefine] from Citi.

Please go ahead with your question.

Thanks, Peter and Simon.

Can I ask you a question on refining because it's sort of eight or nine quarters now of losses in that business, albeit at the bottom of the cycle?

I guess my question relates to the profitability doesn't look anywhere near as robust as some of your peers and I wonder how you think about the 2012 cash flow targets in that context.

Thanks, Allen.

I'll take this from a strategic point of view.

We have clearly outlined how we are rationalizing the portfolio and I mentioned all these numbers.

I think we are well on track there.

The majority of our cost savings actually is coming out of our downstream and a good portion is coming out of the refining.

We are adjusting all of it to this new refining capacity which we have.

And that takes its time.

We have these outages and relatively high turn around work in the fourth quarter, but clearly there is more to be done on the refining side.

But we have all of that at hand or in hand as we are moving forward through that.

As I said in previous calls or previous talks, strategy update in March will be kind of the next news of downstream, how we take it forward.

And I think once we have imbedded our current portfolio of refining, there might be more to come on that side.

But we will talk about that either in March or further down the road when we are getting to that.

A lot has been done.

Availability was high et cetera, but we have some locations and we have disadvantages and some are out of the system and some we are still working.

So, we need a little bit more time here.

It's clearly part our integrated strategy and hence we need to make sure that we have got the right size of refineries with the right through put, and the right overall complexity and we are working on that.

Some new stuff is also coming on stream which will be helpful in that sense as well.

Thank you.

Next person, please.

Thank you.And the next question comes from Oswald Clint from Sanford Bernstein.

Good afternoon.

Maybe just one on chemicals and specifically the new MOU you signed in Qatar.

Obviously chemical returns generally-- roughly around the cost of capital over the cycle of these projects, can you confirm that this new project that in Qatar is going to benefit from advantaged feed stock raw materials through the natural gas stream?

And then secondly, you are talking about your natural gas there and certainly tight gas and expenditures in the US.

I know you had been testing some areas specifically across in Europe and in Sweden.

I wonder you didn't mention it today.

Wonder if you could talk about some of that unconventional gas exploration?

Thank you, Oswald, for the questions.

On the first one, if I heard you correctly saying you were kind of also implying that we are taking advantage of lower capital costs, et cetera.

I think we will see how these will be develop over the next few years.

On the feed stock question, quite clearly we do this together with QP and therefore we go from gas to chemicals, which has its advantages.

We have signed the MOU.

We haven't signed ahead of the agreement and the final agreements, so I think we will give you feedback once we have done that.

I think one of the advantages of doing this in Qatar is around the pricing of the feed stock, but too early to talk in details about it.

In terms of unconventional gas, clearly we have talked about the North America where they are making new progress.

In terms of Europe, Sweden, the exploration, pilot stage, we'll inform once we have confirmed there.

It's too soon to say.

It is, I think in general, in a way slow pace in Europe.

There are quite clearly footprint issues.

There are permitting issues.

Not just in Sweden, but in many other areas.

So, we will see how this develops.

What is much more exciting as China and that's where we have got quite sizable square kilometers of acreage, which we have actually, at the end of the fourth quarter, we started to actually reach the exploration.

We are very excited about those two blocks for shale gas, tight gas and the one block for CBN.

And we think China has got quite a bit of potential in that sense and we will report back on that once we have heard the exploration phase.

Thank you.

Next question, please.

Thank you.

And the next question comes from Alejandro Demichelis from Merrill Lynch.

Good afternoon, gentlemen.

One question.

Maybe you can touch a bit more on what you are seeing in terms of cost increases.

Not just for deep sea, but into transport for you on those growth projects.

And how much of those cost increases you think that could offset the cost reduction that we have seen on Shell oil in the past couple of years.

Yes, thanks, Alejandro.

I'll give that to the guy who manages a lot of these kind of things.

That's Simon.

Thanks, Peter.

Thanks, Alejandro.Good afternoon.

Since 2008, the cost pressure or inflation did come out of categories in the industry, but is now returning.

Two categories that we see significantly impacting the industry are steel and rigs.

Steel impacts about 30% of our capital cost.

Rigs is also a significant element; we are spending somewhere between $7 billion and $10 billion a year drilling.

The costs for 2011 are largely locked in.

Our rig costs for the next two to three years, and in some cases out to five years, are also largely locked in at reasonably attractive levels.

Our average day rate on the fourth and fifth generation, BEB order rigs is below 500,000 a day on average.

Well below, in fact.

We cannot completely mitigate against steel price rises that we see.

Having said that, one significant advantage of our new organization has been the development and perhaps more importantly the execution of global strategies per category of contracting spend.

We spend around $60 billion with third parties each year.

We developed category management strategies and global framework agreements, now over 100 global framework agreements with key suppliers, which is driving our cost down.

Often have imbedded in them low cost country sourcing such as from China, Mexico and elsewhere and that impact is so far offsetting the inflation we see coming back into the market.

This does take careful management with chosen suppliers, but we are hopeful that we can not only continue the downward trend in OpEx, but avoid significant inflation on the capital again as we take new investment decisions going forward.

So, if we have to look at the upstream overall costs, we can see that trend of cost reduction kind of changing here?

Mind, it's difficult to see, it's even difficult for us to monitor the actual unit cost of any given units of activity.

For example, onshore gas drilling we know we drive the cost down through better performance.

Over time when we shared that with you before.

Offshore drilling equally over time in any given activity we do take costs down.

Each large project tends to be unique and difficult to benchmark.

What we will aim and do aim to do is to benchmark the project at the point at which we take decisions and which the points we deliver them.

I can share with you that our benchmarking done by the IPA does show us significantly improving in both upstream and downstream projects over the past four years.

We are in a reasonably good position there and intend to stay there.

Thank you.

Thank you, Alejandro.Next question, please.

Thank you.

And the next question comes from Irene Himona from Societe Generale.

Good afternoon.

I had two questions, please.

First of all, the depreciation charge year on year is up roughly $1.1 billion.

Is that clean?

Are there any impairments in there?

And should we expect a similar increase in 2011 as the new projects start up?

Secondly, I don't know if you can update us at all on organic reserve replacement.

I suspect not, in which case I have a third question which is this.

Pre 2004, 2005, Shell used to have serious and persistent operation problems in its refineries, particularly in North America then you appeared to have resolved that.

It seems to be back.

Can you talk about the specific operation problems that you are encountering in Q4 and Q1, 2011?

Thank you.

Thanks, Irene.

I think I'll leave number one, the depreciation, and number three, the refining, to Simon and take the middle one which is an easy one.

We will, as in the previous years, we will give you those numbers when we have the strategy update, i.e.

when the 20X comes out, which is around the same time.

Okay.

Then depreciation and refining and what exactly has happened in Q4 and Q1 to Simon.

Thanks, Irene.

2009, 2010 depreciation both had impairment impacts and, if you remove the impairment impact, was also an asset sale impact.

The underlying depreciation went down slightly from just over $12 billion to just under $12 billion.

It's a fairly constant $3 billion per quarter charge, no expectation it will change materially in the coming year.

Although as the big projects come on stream, you will start to see that nudge up.

I can't really speak to pre 2005 activities in the downstream, but in Q4 specific issues on refractory linings, furnace linings, and cap crackers in Port Arthur, that's driven by basically faulty equipment supplied five years ago, should have lasted 25 years and needs replacing after five.

This is an industry problem.

One or two of the competitors had exactly the same issue with the same supplier.

So, not endemic.

One or two of the other troubles we have had were unfortunate.

We are not satisfied with the performance we have seen.

We see it as a bump on the road more than an endemic issue with the manufacturing side.

Thank you.

And next question.

Thank you.

And the next question comes from Theepan Jothilingam from Morgan Stanley.

Couple of questions.

Turning back to the startup costs.

I imagine that sort of increased through the year.

I was wondering if you could give some sort of guidance on how you see that.

So, let's say 12 months on from here.

Or how you would suggest we model that into our numbers.

Just sort of follow-up just in terms of the upstream any thoughts on how maintenance levels will be in 2011 relative to 2010?

Do you see an increased level or not?

And then the question perhaps of Peter.

I mean, you talked about the disposal program sort of slowing down.

I can understand that perhaps in the downstream, but sort of looking at the upstream it does seem to be a seller's market.

I was just wondering if you could give some thoughts around why perhaps Shell shouldn't look to use this as an opportunity to monetize some of its, let's say, bottom quartile assets.

I think, Theepan, I start with the last one to give Simon a little more time to think about one and two.

Our portfolio management is key from that point to changing the strategic industry you are putting on the portfolio management.

Clearly the growth strategy in order to deliver actually production growth over time.

So, it's quite clearly this is a distinction to some of the talks which are in the market about shrinking.

I find shrinking rather easy.

Growing is really more difficult.

So, from that point if you clearly look at the portfolio management, slowing down what I said is I just don't want you guys to think that we will do another $8 billion or something like that in the next 12 months.

We will do five and then we will see how the market is over the next 12 to 24 months and then guide you further.

For the moment it's five to 11 and otherwise I think, long term, go back to what we have always have given as a guidance, which is slightly lower than that.

We are clearly focused on it and if the market is right, we have non-core assets or life assets, we will not be shy to turn the portfolio over in the near future.

But we will clearly keep a focus on gross and this is, as we have always said, a clear driver for our 80% increase in cash flow and an $80 world by 2012.

We will make sure that we actually deliver that.

So, for question one and two over to Simon.

Thanks, Peter.

Start up costs, broadly speaking, around $200 million in the upstream in the fourth quarter.

You can expect that level to continue into the first quarter as we start up the upgrade in Canada, and the two projects in Qatar and the basically the work we are doing in Iraq.

It's a bit plus or minus, but it does (inaudible) the magnitude.

It will go down by definition as we get into the second half of the year.

And that's a pre-tax figure, of course.

Divestment -- sorry, the upstream maintenance levels.

We have no expectations that maintenance levels will be any different next year from what they have been this year.

The two biggest issues in our upstream are fundamentally Nigerian availability largely driven by security and Gulf of Mexico return to activity.

The rest of the portfolio is pretty much on track and is out there operating very well.

Great.

Thank you.

Thanks, Theepan.

And next question, please.

Thank you.

And the next question comes from Kim Fustier from Credit Suisse.

Hi, good afternoon, gentlemen.

I have two questions, please.

First is can you talk a little bit about the associated gas deal in Iraq and whether you are confident it will be finalized by the end of this month?

And secondly could you talk about the delays sanctioning and CapEx overruns on cash against these too, and whether there is any scope to relaunch the project?

Thank you.

Okay.

I'll take both of them.

On the south Iraq gas deal, I think as we always said, there is great, great benefits to the Iraqi people, especially the Bozrah area in getting on with this project to generate domestic cash for power generation later on export by LPG or LNG.

We have had various rounds with the governments and I think you are referring to the same press release or press statements I have seen, that it is ready by the end of February.

I would just say I think we have well progressed, it's negotiated.

It's up to the Iraqi government to come to a conclusion under resolutions.

The timetable is in there hands.

I cannot say much more than that at this stage, but I'm somewhat optimistic that we will get it over the line soon.

On cash in two, I guess first of all let us work or he and I work and catch the first stream.

I think this is pre FI and pre FID.

We are looking into where it has options, could be modernized, could one project and we are in that phase at this stage and too early to talk about it for the longer term.

So, I think we will update on this once we go further in the pre FID work, so not much more to say on this one.

And thank you for the questions.

And the next question, please?

Thank you.

And the next question comes from Iain Reid from Jefferies.

Good afternoon, Peter and Simon.

Can I ask a specific question about Nigeria?

You've obviously been selling undeveloped discoveries to the indigenous companies.

I wonder whether you are going to go past that, or further than that and dispose of any of your existing production given the fact that, as you said earlier, it's fairly low margin.

And second question about Australia.

Perhaps you can just tell us how close you are to FID on Prelude and whether you can give us any indication what the cost of that might be.

And also where you are on the coal bed methane Arrow development.

Thank you.

I take a second one and the first one and Simon can take on Nigeria.

On prelude we are making good progress in the whole feed discussion, and as we have said, this is a key FID target for 2011.

We are getting closer to it.

Prime work at the moment is clearly done around the technical side, but also around the costing side.

As you know we do not disclose cost by project in any project, but I think I would summarize it as we are making good progress on a, advancing it, but b, optimizing the costs.

So, the second one was FID during 2011.

Arrow making good progress.

You may have seen some of the press releases from Arrow.

We are inviting the companies for the feed that should happen during 2011.

And as usual, we will update on the progress of what's happening in Arrow, the joint venture with CMPC, during the quarterly calls to come.

So, not much more at this stage to say on that one.

Thank you.

And to Simon.

Nigeria unsure.

We have 38 blocks overall.

Very widespread portfolio across the area with population 35 million people and an area that exceeds the size of Belgium.

It's a very broad and diverse footprint that we have.

Our strategic aim has been to reduce the size of the footprint by increasing the participation of Nigerian companies and stake holders in the production activity.

Of those 38 blocks, last year we sold four blocks.

And the results of which are in the 2010 financials.

We currently have another four blocks on offer and that's what you may have seen some press about recently.

We still have 30 blocks.

The blocks sold and for sale represent less than 10% of our production there.

We are really reducing the footprint, increasing indigenous participation.

In line with the Nigerian government objectives as well, it has to be said.

We don't have an intent to mitigantly change further the footprint, we are focusing on the core oil and gas areas.

And that's the strategy as it stands today.

Thank you, Simon.

And next question.

Thank you and the next question comes from Mark Gilman from Benchmark.

Simon and Peter, good afternoon.

Couple of things.

Simon, I wanted to go back to a comment I thought I heard you make in response to a question regarding 2011 DD&A being roughly comparable to 2010 on a clean basis.

Could you clarify that and explain how that is possible and why incremental Athabasca and Pearl DD&A are quite sizable?

And I have a follow-up.

Puts and blade, both the Upgrader and Pearl will be straight line depreciation, not units of production which means they don't kick in at the heavy level.

Plus, and then this is not a projection at all, track record of adding reserves recently is generally meant that the depreciation has gone down slightly in the upstream year on year.

Without giving anything ahead to that plus the fact that the big two are straight line, and that means we won't see a map -- a big step up during the year.

Alright, yet I'm a little bit confused by a comment in the presentation regarding the exploration results in 2010.

Eight discoveries yielding net $250 million equivalent of resource.

Suggests that this is not exactly a high impact kind of program.

Am I mixing apples and oranges by putting those two things together?

You could be there, Mark.

We haven't given the total results add from the exploration programs.

The eight discoveries, of course we have from the tight gas activity.We will give the figures when we finalize them in the March presentation.

The $250 million refers to Appomattox, which is a single discovery.

The single largest discovery in the Gulf of Mexico.

Okay.

One more for me.

The integrated gas earnings in the fourth quarter were sharply below anything we were looking for.

Can I assume that, that is where the lion's share of your reference start up costs have hit?

No.

Basically it's a dividend from one of the LNG companies that was large in Q3 and absent in Q4, hopefully back again in Q1.

Plus the fact that some of the ramp up in volumes was Nigerian, which was effectively going into spot markets.

The actual average realized LNG price was down on average slightly for the quarter.

Versus third quarter or --

Versus third quarter.

Yes, I'm talking about third quarter, Mark, as opposed to year on year and the realized gas prices are quite significantly up year on year versus Q4, 2009.

Sorry for not being clear.

Okay.

Thanks, Simon.

Thanks, Mark.

Next question.

Thank you and the next question comes from Jason Gammel from Macquarie.

First of all, with the Gulf of Mexico and Alaska now, I guess more or less off limits for the next two years from an exploration standpoint.

Can you talk geographically about where you could have high impact exploration?

And then secondly, given the huge discrepancy on a BTU basis between natural gas and liquid product globally, would you be looking to invest incrementally in gas liquids projects?

On the first question, I think I didn't say that it is off for the next two years.

As I said we have actually the first company which now has three exploration wells actually kind of in the public discussion now.

So, they have fulfilled all their agency requirements as published through a press release last Friday by the authorities.

So, we are in that phase so we are really hopeful to get back into the Gulf rather sooner than later.

Alaska, I've said clearly again it's not two year, it's for 2011.

We are preparing the permits so we can actually drill in 2012.

I just don't want to spend the money as we still have uncertainties and you would have to spend $100 million to $150 million between now and getting there maybe no answer and then we would have to actually dismantle what we have already built up and prepared.

For all the rest of the explorations, I think we will give a key update in March as well.

You can obviously see in the presentation slides there are some indications there where we have clearly some new acreage, et cetera.We will get you a clear overview on how the exploration program will exactly work in the March presentations.

Can you just repeat your second question?

Just given the large discrepancy in pricing on a BTU basis between natural gas and the liquid products, would you consider incremental investments in gas liquids?

Thanks for that.

I've always said I wanted to finish Pearl, start it up and have a very smooth kind of transition into full production there.

Then we can have another look at what's possible.

The most logical one would be train three.

As you may know we are constructing Pearl in such a way that tie-ins for train three are already there, the land is also booked and reserved, et cetera.

So, that's quite clearly the one which would come to mind for the next step.

Therefore the answer is yes.

If you have the right conservists, the right reserves, the right pricing, from a feed stock point of view then that could be a attractive, but I think let us finish Pearl first and operate and then come back to that.

Thank you.

Let's go to the next question.

Thank you.

And the next question comes from Jean-Pierre Dmirdjian from Oddo.

Yes, good afternoon, gentlemen.

I have three questions.

First question can you indicate for us exploration expenses in 2010 and the dedicated budget plan for 2011?

My second question is regarding the concessions in Abu Dhabi which is expected to expire by the end of 2013.

If I'm right, can you indicate for us as you mean the concession is not renewed, the possible impact on your project churn and what would be your new 2014 prediction guidance and the impact on your earnings?

And my third question is regarding a dividend policy.

You are expecting a stable dividend in Q1 2011 as we saw this quarter, what are the key drivers that may increase your dividends for the future quarters?

Thank you.

Question one and three to Simon, I will take two and then Simon you want to start?

Exploration and expansion is getting tricky to actually report now because the unconventional gas activity becomes exploration or development almost well by well.

Depending on exactly where it's drilled in terms of recognized reserves.

So, I was thinking in more general terms.

The amount allocated by budget is just over $3 billion in 2010 and again in 2011 through exploration activity, that's seismic and drilling.

About half of that is spent on drilling.

No real increase.

What actually gets reported as expenses does vary for that reason in unconventional gas.

Abu Dhabi -- I'm so sorry, I will leave Abu Dhabi for Peter.

The dividend.

The key drivers of the dividend, the dividend policy that we restated last year is growing in line with earnings and cash flow.

We also said it is our intent to balance cash flows by 2012 at $60, such that we earn from cash from operations.

Enough to support $25 billion to $27 billion of net investment and $10 billion of dividend.

The big drivers of that cash flow growth to get us back to that, behind the equilibrium position are the projects.

As we go through this year and big three projects, the target cash flow, the two Qatar projects, and the Canadian oil sands should ramp up.

That's what a we expect as and when they come on stream.

That plus the balance sheet, plus the ongoing oil price development will drive the discussion about dividend growth.

Peter?

Abu Dhabi, a little bit early to talk about this, but the fiscal terms are based on a tax royalty structure with a fixed post tax earnings of $1 per barrel lifted.

Yes, indeed the production license expires in 2014 and we produced 132,000-barrels in 2010.

I think with that you can do all your sums and your totals.

Thank you very much.

Next question?

Thank you.

And the next question comes from Neill Morton from Berenberg.

Good afternoon.

Two quick numbers questions, please.

Firstly, could you perhaps see how much of the fine set increase in production in 2010 would you call the weather?

Year on year.

I think Simon you may have given us a profit impact on that as well.

That would be useful.

And just secondly, could you quantify your expectations of production growth from new field startups and ramp-ups in 2011 versus the 170,000-barrels you achieved in 2010?

Thank you.

Over to Simon.Thanks for your question, Neill.

A couple of impacts there and control in terms of OPEC demand constraints and the weather by a 60,000 barrels a day increase year on year 2010 versus 2009.

If you remember, it was very cold, not only in Q4, but also Q1.

It's a lot warmer this year, is all I would say on that.

Sorry, could you repeat the second question?

It was just your expectations for production growth in 2011 from the startups and ramp-ups.

We would hope it would be higher in principle because we should get best part of the year out of oil sands and we should see the impact of full year, for example, of [Bar on EBA of Yowar] of hopefully we will get back to Perdido and the Qatar projects will start to ramp up.

And I wouldn't want to give a pseudo production forecast for 2011.

We said broadly similar but with quite a wide range of potential outcomes, both positive and negative, depending on for example the weather, Nigeria and security and the rates of those ramp-ups.

Broadly similar plus or minus.

One quick clarification, on refininery availability in Q1, you said it was frac to lure.

Was that versus Q4 or was it year on year?

Versus Q4.

Versus Q4.

Thank you.

Thank you.

Now we go to the last question.

Thank you.

And the final question comes from Sergio Molisani from UniCredit.

Good afternoon.

Quick question, if I may.

First, on the tight gas.

If I understand well, you are guiding for the low part of the three to five year total billion topics indicated on the location of the North American [strip].

If I'm correct, what you read across we may take from these decision in terms of gas price you expect for 2011 and 2012?

And second question is can you give us an update on the exploration in Brazil in the BMS54?

And the third question is a follow-up of the Neill question in regarding the production guidance for 2011.

Do they understand well that you expect more or less flat production versus 2010?

Thank you very much.

I think Simon can do all of them.

Thanks, Peter.Does the low end CapEx indicate low gas prices?

Well, initially to an extent yes.

We are drilling where we need to hold acreage and where we've already got the cost stand to the point we can make money at $4 and that's what's driving us.

The gas price goes up, we will see where we go.

Because it's relatively easy activity to ramp up.

BMS54 exploration just reminded us is an 80% shell block, now with 20% totally.

We have two prospects to drill.

We drilled one late last year.

We hope to drill roughly the middle of this year the second prospect.

There are two reservoirs horizons in both prospects.

We are currently evaluating the first well.

It looks prospective and we have indicated -- this is not a multi-billion barrel prospect, but it looks very interesting at the moment.

We need to drill the second well, do the appraisal work before we can really say anything further.

2011 production, the statement is broadly simple, but with a wide range of relatively wide range of outcomes.

We actually increased our production in Nigeria on shore baron 100,000 barrels a day or over 100,000 barrels a day in 2010 versus 2009, in the current security environment and with Bar on EBA, the gas project, up and running we can do that or better again in 2011.

But there is an election in Nigeria this year and that's a level of uncertainty.

In the Gulf of Mexico we lose 50,000-barrels a day of high value production compared to what we would have expected to have delivered if there had been no moratorium.

And we do not drive the pace at which we are able to restart development and production drilling in the Gulf of Mexico.

It's unfortunate, but there are a significant number of factors outside of our control.

Our aim and expectation for 2012, because we control most of the main drivers of 2012, is to deliver the 3.5 million barrels a day target.

Even though the divestments we have done will in fact reduce production in 2012 by around 80,000 to 100,000 barrels a day, compared to what we had originally projected.

Good.

Thank you very much, Simon.

And thank you for all of the questions today.

And thank you for joining us for this call.

We are having an Investor day on the 15th of March in London, with the global rate cost.

We will also make this more interactive with breakout Q&A sessions with our business leaders and I hope to see many of you there as possible.

Thank you again for calling in.

And have a good rest of the day.

Thank you.

Cheers.