殼牌 (SHEL) 2011 Q1 法說會逐字稿

Thank you for holding, ladies and gentlemen.

Welcome to the Royal Dutch Shell Q1 results announcement call.

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

(Operator Instructions)

I would like to introduce our host, Mr.

Simon Henry.

Please go ahead, sir.

Thank you.

Good afternoon and welcome to Royal Dutch Shell's first quarter 2011 results presentation.

First the disclaimer statement.

I'll now take you through the results and leave plenty of time for your questions.

Our CCS earnings, current cost of supply, excluding identified items was $6.3 billion in the first quarter.

That was an earnings per share increase of 29% compared to the first quarter of 2010.

Our earnings have increased from year-ago levels in both upstream and the downstream.

The results in the quarter really are a snapshot of our delivery on strategy, our focus on improving near-term performance and on delivering profitable growth in the medium and longer term.

We have announced new asset sales and cost-saving programs, all part of the focus on continuous improvement, and it helps enhance profitability and performance.

We sold $3.2 billion of non-core assets in the quarter, further disposals in hand.

We're delivering the growth projects that we've launched over the past few years.

This drives the growth to 2012, and it's clear we're working on new options for the next wave of investment for the growth to 2014 and beyond.

During the quarter we started production at two new projects, the Schoonebeek heavy oil project in the Netherlands and Qatargas 4 LNG project in Qatar which together would add 90,000 barrels of oil equivalent per day for Shell when they're both at their peak production.

We continue to crystallize new investment options for the medium term with exploration success and entry into the Chevron operated Wheatstone LNG project in Australia.

For the next wave of growth to 2020, we have over 30 new projects on the drawing board at the moment which will generate new options for growth in that period, so we're making good progress against our targets to deliver a more competitive performance from Shell.

So let me move to a few more details on the results starting with the macro.

If you look at the overall macro picture compared to the first quarter a year ago, oil prices and our gas realization increased.

However, the spread between oil and natural gas realizations remains relatively wide, and North American gas prices actually declined.

Chemicals margins increased in most regions against first quarter last year, although with lower margins in Asia and we had a mixed refining environment.

Industry margins declined in Europe and the US Gulf Coast and increased in Asia and the US West Coast.

However, our own refinery configuration delivered increased margins in the US, broadly similar margins in Europe, and a decline in Asia.

We've updated the industry refining margin trackers that we show you here for the US Gulf Coast and for Europe in the results announcement that we made today.

These changes reflect the declining availability of purebred crude and market discrepancies in WTS, West Texas South, prices.

We switched to margins based on data, Brent which is a blend of North Sea crudes rather than that purebred price for the European refining margins, and we switched to a mars coking margin for the Gulf Coast rather than WTS.

Turning now to our earnings, the headline CCS earnings are $6.9 billion for the quarter including identified items of $0.6 billion.

The CCS earnings excluding identified earning items was $6.3 billion, the clean earnings, and the underlying EPS increased by 29%.

Cash flow from operations generated in the quarter was $8.6 billion or $13.1 billion if we exclude working capital movements, and the dividend for the quarter is $0.42 per share as we had previously indicated.

We're offering a scrip dividend program for the first quarter of 2011 where eligible shareholders can take the dividend as new shares.

All the information for that, of course, is on our website.

The quarter saw higher earnings in both upstream and downstream, so let me talk about the business performance in a bit more detail, firstly the upstream.

Excluding identified items, the upstream earnings increased by 8% to $4.6 billion in the first quarter, and that compares with the first quarter last year.

The main drivers in these results were higher oil and gas prices and higher dividends from an LNG joint venture.

These positives were partly offset by increased in costs relating to the startup of new projects, increased feasibility study costs and higher taxes.

Earnings were also impacted by weaker natural gas trading results, divestments and maintenance down time.

Upstream production at 3.5 million barrels of oil equivalent per day, that declined year on year by a headline 3%.

We saw reduced demand for gas in the quarter, some 50,000 barrels oil equivalent per day.

We had 90,000 barrels of oil equivalent per day of maintenance downtime impacts, and the divestments had an impact of 85,000 barrels of oil equivalent per day.

However, the underlying performance was better and volumes were flat on year-ago levels excluding only the impact of the asset sales.

The LNG volumes increased by 4% to 4.4 million tons reflecting higher volumes from Nigeria and the startup in Qatar, and production overall from new fields and field ramp-ups was around 230,000 barrels of oil equivalent per day, higher than it was a year ago, and that more than offset the underlying field declines at around 160,000 barrels a day, all reflecting the medium-term plan for production and cash flow growth where the key targets are, of course, next year, 2012.

As you know or will know, the UK government announced during the quarter a tax increase for the upstream.

There is a negative impact of some $60 million from this in our first quarter results on a clean basis.

To give you an idea of the forward impact, at current oil prices we're expecting a further $150 million charge for the rest of 2011 and then an increase to around $100 million per quarter for 2012.

In addition to these charges we're expecting to take a one-off $500 million charge for the tax change relating to the deferred tax provision on abandonment cost once the legislation is actually enacted, and we think that's most likely in the first quarter of 2012.

Turning now to the downstream, excluding identified items, the downstream CCS earnings increased substantially from the first quarter last year to some $1.7 billion.

Refining made a small profit compared to the year-ago losses.

In fact, it was the first profit for a couple of years.

Refining earnings also improved from the fourth quarter of 2010 where we had impacts that we advised from downtime at the catalytic crackers at Port Arthur in the US and Pernis in the Netherlands, and both of these came back online during the first quarter.

For the second quarter we do expect refinery availability to be lower than it actually was in the first quarter, and that's due to planned turnaround activity in both Europe and North America, and that's just normal turnaround.

The first quarter marketing earnings increased from year-ago levels.

It was driven by higher trading and lubricants results, albeit these were offset partly by lower retail figures where of course higher oil prices do tend to reduce margins as the price goes up.

Chemicals earnings increased from year-ago levels underpinned by higher margins and volumes.

However, we did start to see the impact of weaker industry margins in Asia and maintenance downtime at our own Bukom chemicals facility in Singapore, and that maintenance downtime will continue for most of the second quarter.

So those are the earnings and I'll turn to the cash flow.

Cash generation on a rolling basis, a 12-month rolling basis, was $46 billion.

That includes $10 billion of disposal proceeds, and over that period the Brent oil price averaged $87.

This combined with the ongoing capital spending program, this resulted in a slight reduction in the balance sheet gearing in the quarter to 14%, and that compares with the 17% we saw at the end of 2010, and also fits very well in the 0% to 30% range that we look at for the Company in the overall financial framework.

I should update you that we expect to complete the Reizen joint venture.

That's the sugar-ethanol downstream marketing joint venture in Brazil.

Expect to complete sometime in the second quarter of 2011, and when we do that we will recognize $1.6 billion as capital investment.

You will see that then flow through as cash out of around $600 million on completion, and that's the first of three payments over the next couple of years so we don't see all the cash going out immediately.

We will continue to watch the cash position and the balance sheet very carefully, and I'm pleased to see this quarter the inflow and the outflow rebalancing to a surplus, albeit it assisted, of course, by higher oil prices and the asset sales.

Let me just recap on the asset sales which are an important part of the continuous improvement program.

They help improve our capital efficiency and more importantly refocus the portfolio on profitable growth assets.

The sale proceeds for the quarter were $3.2 billion.

Upstream we concluded $2.4 billion of these.

That covered 60,000 barrels of oil equivalent per day of production with the prime transaction being the exit from the South Texas tight gas production.

In the downstream we concluded $800 million of non-core marketing position divestments, and that's overall a very good start against the plan for this year to divest up to $5 billion of assets.

In addition during our first quarter we announced further potential asset sales which should complete later in 2011 and 2012.

Now, these included in the downstream selling Stanlow refinery in the UK and reducing our marketing exposure in Chile and in several African countries.

We also began at the end of the quarter staff consultation to convert the Clyde refinery in Sydney, Australia to an import terminal, all this further proof on refocusing the downstream portfolio for higher profitability and selective growth.

And I guess you all know we're still working on the $1 billion of cost reduction for 2011/2012 that we have targeted from the downstream.

Turning now to the growth, I mentioned we started two new projects in the quarter, part of a sequence of over 20 new projects in the full-year 2011/2014 timeframe.

In the Netherlands we restarted production at the 20,000 barrel a day Schoonebeek heavy oil project.

Schoonebeek is actually a rather old field.

It already produced 250 million barrels since 1947 when it first came onstream.

The field was shut in for economic reasons in 1996, but we looked at it again to find ways to extract more oil from this.

With our value-added technology, the near steam flood scheme is expected to produce a further 120 million barrels over the next 25 years, and that's almost a 50% uplift on recovery.

In Qatar I'm delighted to confirm we had a very successful startup so far at the 7.8 million ton per year Qatargas 4 LNG project.

That train is now running at full capacity and has been from the beginning of April.

It delivered its first LNG cargo only on the 19th of February to Hazira in India, so very quick ramp-up.

Later this year Qatargas will start deliveries to Dubai and China in line with the long-term contracts.

Staying in Qatar, and I'm sure you'll have an interest in this, we also achieved first gas from the offshore into the Pearl GTL project.

This is an important milestone for Pearl ahead of the GTL train one startup sometime in the middle of this year.

We've actually now started to make [sin] gas in the first bank of reactors at Pearl in the first train.

This is our Shell proprietary technology.

The next step is to take that [sin] gas into the GTL reactors to make the wax.

After that we take the wax into what you may recall the refinery conversion units at the end of the train before we produce that first product sometime in the middle of this year.

Worth also I think an update on Canada growth.

In the oil sands we're making good progress starting at the expansion project.

The mine production is gradually increasing and we're actually using some spare capacity in the original Scotford Upgrader to process this bitumen.

The construction of the new upgrader, the expansion was completed in the first quarter.

We're now in early commissioning stages and we should be fully operational by the end of the second quarter as planned.

So overall, particularly on those big three projects, good progress bringing them onstream, on track, growing the Company towards 2012.

Looking out a little bit longer beyond 2012, we've also made progress crystallizing some of the longer-term options.

Just a reminder we are planning to take final investment decisions on some ten new projects in 2011/2012.

These include Prelude floating LNG in Australia, debottlenecking the Athabasca oil sands project, and deepwater oil and gas developments at the Cardamom discovery in the Gulf of Mexico.

In Australia we've just included our share in recent gas discoveries in the Carnarvon Basin.

We've included that into the Chevron operate Wheatstone LNG project, so now in that project we have an 8% state in the unitized gas fields for upstream production and a 6.4% stake in the liquifaction facilities to produce LNG.

Wheatstone is being designed as a two-train, 8.9 million ton per year LNG project.

On the expiration side we also confirmed during the quarter the significant Geronggong discovery in deepwater Brunei.

It was actually drilled last year, announced in the quarter, resource potential of some 200 million barrels.

So just to summarize, excluding identified items, the CC earnings per share increased by some 29% year-on-year.

Our performance in the quarter we believe underlines that we are delivering on our strategy.

We're making good progress on our three strategic themes.

That's the shorter-term performance focus, the medium-term growth delivery to 2012, and creating the new growth options out into the rest of the decade.

Our priorities remain a sharper delivery strategy, aiming for profitable growth and a more competitive overall performance.

So with that let's move to take your questions.

Please could you try and restrict yourselves to just one or two each so that we have the opportunity for everybody to ask a question.

Operator, please could I ask you to poll for questions.

Thank you.

Thank you.

We will now begin the question and answer session.

(Operator Instructions) The first question comes from Oswald Clint from Sanford Bernstein.

Please go ahead, sir.

Good afternoon.

Maybe just a question on Asian gas, and I'm just wondering with the strong Asian gas demand and the Japanese events of the quarter, how you're thinking about demand in that region, and is there any thoughts around Sakhalin 2 in terms of it being expanded?

Is that something that could be done?

Is it something you're thinking about and do you -- would you have sufficient gas in the region to think about a third train there?

And the second question just on your European gas production in the quarter was down quite significantly.

You mentioned some reduced demand there.

Could you just say if that was actual production declines or was that a pure demand phenomenon?

Thank you.

Thanks.

I see some of your research covering this subject, Asian gas, so thanks for the question.

The Asian gas demand short term, yes, has been impacted by the Japanese situation.

We've diverted I think around 11 cargoes, either swapped or diverted into Japan to try and help with the power situation there.

We're basically putting it in at normal contract price.

It has an impact but essentially it's not making a big impact on earnings.

We think they could be taking up to a million tons a month for some time, which actually adds up to more than Sakhalin's production if it were to continue in that level for a year.

Medium and longer term we've always seen Asian gas demand as a prime driver of our strategy.

About a third of the demand, global gas demand growth in total comes from China and close to another third from Asia and/or Middle Eastern markets, so about two-thirds overall and we don't see any reduction in that.

If anything, it's potentially an increase.

What we have certainly been able to do over the past three to six months is take all spare gas because Qatar is producing earlier and faster than we had expected so we have had spare gas, but it's -- Qatar has been able to market that away from North America and into the higher-value markets in Asia and Europe.

The question about Sakhalin 2, the expansion is obviously technically and operationally possible.

We have in November signed an MOU.

Peter was with Gazprom in November where we agreed to look at opportunities to expand our activities in Russia and potentially to -- with the flip side being cooperation in projects outside Russia with Gazprom.

We continue to look at that opportunity with Gazprom.

It would almost certainly require us accessing more gas in the Sakhalin 3 area which is under Gazprom control, but we have no real progress to report on that.

So, yes, we'd be interested.

No, we don't have concrete milestones on that.

Our main growth in gas production to supply the Asian market will come from Australia, the multiple projects that we have there.

On the European gas production, I mentioned 50,000 barrels of oil equivalent per day reduction, estimate 300 million [scuffs].

That's nearly all in Europe and primarily driven by the weather.

It was colder last year, very cold last year in Europe.

It was actually unseasonably warm this year, so quite a big difference.

So many thanks for the question, Oswald, and hopefully that's okay.

Yes.

Thanks, Simon.

Your next question comes from Mr.

Jon Rigby from UBS.

Please go ahead.

Thank you.

Hi, Simon.

Hi, Jon.

As you highlighted refining returning to profit, and it's not obvious from the data series on your refining margins why this quarter will be profitable and some of the historic ones wouldn't have been on the basis of macro.

So could you just sort of talk a little bit more about the moving parts that got you sort of above the break-even point this quarter and how much of that is sustaining and how much is maybe temporary.

I guess disposals might have an effect, right?

Potentially.

I mean, that's a good, good question, Jon, and it's actually the first profit I think since the last quarter of 2008 in refining, but it's so small it's not material.

So nearly all the oil products earnings came from the marketing and trading sector.

And you're also right it's difficult to correlate the industry margins with our own performance.

Two reasons drive that.

One is availability where the availability of the units was quite a bit higher than it was last year as well as the utilization of the units.

We also -- in the North American market the actual coking margins we were able to deliver were relatively attractive.

So basically it was good North American refining and the fact that their availability was much higher.

I would just highlight though that although we've given traditionally refining splits and marketing and trading together, we are divesting refining capability to the extent that our marketing sales of over 4 million barrels are becoming increasingly greater than the refining throughput of 3 million and decreasing.

And our actual trading activity is how we join the molecules together, so as we go forward it's really the integrated value chain that drives us more so than a separate view of refining and I think that's something we may need to consider as we go forward.

It's becoming a bit of an odd split given the business model that's evolving as we decline our refining base.

So hopefully that helps.

Yeah, thanks.

Thanks, Jon.

Your next question comes from Alastair Syme from Citi.

Please go ahead.

Hi, Simon.

My question actually also relates to refining.

I guess you're having the same difficulty.

And if you look at the -- you disclosed the cash flow in the quarter of about $4 billion, and if I'm right I think you were sort of talking about 2012 targets of about $12 billion overall across the downstream piece.

So do we interpret therefore you're well above mid-cycle or are performances well on track on that 2012 target?

Another challenging question.

Thank you, Alastair.

The oil products cash from operations does benefit by definition.

It includes the Cosan adjustment, so there's nearly $2 billion in there for the quarter that essentially is a one-off impact that goes up and down so the underlying delivery is somewhat less.

So, no, we're not there yet, and technically we've not given a specific split of the downstream contribution to the cash flow target for 2012.

Yes, we clearly need to uplift from previous years delivery, but we've not given a specific split and we won't do so, either, and we retain the right to deliver.

So are we above or below mid-cycle?

I think we're heading back towards mid-cycle.

I don't think we're there yet.

Hopefully that covers it.

I think so.

Your next question comes from Lucy Haskins from Barclays Capital.

Please go ahead.

Afternoon, Simon.

Perhaps a bit of follow-through in terms of the downstream comment.

You did actually talk about improving [lose] in the quarter but also improving trading.

Could you quantify what the data was in terms of the trading contribution relative to 4Q.

And then the second question was perhaps a slightly a bigger-picture question.

Obviously sort of some companies are thinking about the opportunities to look at liquifaction within the US.

Do you think that's something you might look at over time?

Thanks, Lucy.

We don't expect to have the trading results partly for the reason I just stated.

Our trading activity is not a separate desk.

It is the way we optimize value through the integrated hydrocarbon value chain so there is an uplift in trading.

It was a more volatile quarter, but it's only possible because of refineries and stock positions and marketing around which we can trade.

So overall marketing was back at above $1.1 billion.

Marketing and trading together I think back in the fourth quarter it was more like 400 or so, so it's quite a significant uplift overall and that reflects a pretty strong marketing performance, too.

Liquifaction in the US, I think we've sat around the strategy presentation time.

Yes, it's something that we could be interested in.

Are we actively pursuing a project at the moment?

No.

It's a question of getting the capital costs down to a level at which it makes sense relative to the alternative means of monetizing gas and that our -- well, sorry, I'm thinking a little bit about gas to liquids.

But in principal LNG and GTL and gas to a transport or even gas to chemical, there are all different ways of monetizing gas in -- against liquids prices.

Yes, we are interested in LNG and looking actively, but it would more likely be in Canada than the United States.

We're still not convinced that the US has thought through the potential energy security issues around export of gas from the Lower 48, so I think Canada is a more likely scheme there.

On GTL, gas to chemical, gas to transport, these are all more ideas for the medium to longer term if, in fact, gas-to-oil arbitrage opportunity remains as strong as it today.

Simon, I think you've quantified in the past that GTL probably is a go if you don't see gas prices much above $6, but it starts not to hang together sort of above $8.

Do you have -- can you give some order of magnitude in terms of liquifaction?

Well, in terms of GTL, we said that the current gas-to-oil differential would probably make it attractive.

We're not sure that this differential will sustain for a period long enough and sustainably enough to make that kind of investment.

What we need to do is continue the work on the catalyst development and on getting the liquid capital costs down.

We will learn a lot from our own project in Pearl and Qatar.

That will help us on the potential future efficiencies that will help us to answer that question better.

But clearly there is potential in the much longer term and it would require significant investment to help convert some of the gas exposure to liquids.

Thank you.

Thanks, Lucy.

Your next question comes from Irene Himona from Societe Generale.

Please go ahead.

Good afternoon, Simon.

Hi, Irene.

I had a question on the cash flow.

I note you highlighted the delivery of $4 billion to $6 billion of cash including the disposals in the past sort of four quarters.

So if I'm not mistaken, your target is $43 billion cash from operations excluding disposals, in which case on my numbers you delivered about $36 billion on a rolling four-quarter average on an $87 oil price, so there's still a gap of $6 billion to $7 billion to the target.

And my question really is trying to think about the timing of a possible dividend increase, should we be thinking -- should we anticipate that you will look at that once you hit the targets or given the external pricing environment which is substantially higher, could that come earlier than next year?

And then my second question on upstream performance, I mean clearly it was weak versus expectations but also versus your own price sensitivities.

Is the gap mostly the startup costs, in which case what should we anticipate for the rest of the year?

Thank you.

Thanks, Irene.

Good question around the CFFO.

Your first point is your arithmetic is absolutely correct, $36 billion, rolling 12 months, $87 a barrel, so still something of a gap, $6 billion or $7 billion.

You may recall that we always said Qatar was about a third of the uplift or around $4 billion at $70 oil price so neither of the Qatar projects is yet actually contributing anything material in the first quarter.

At what point do we consider the dividend?

Well, firstly it's a broad consideration on a quarterly basis.

We changed the dividend policy last year to imply that essentially it's the structured cash flow delivery.

The dividend will grow in line with cash flow and earnings.

We're not quite there yet.

We'd also need to take a look at the balance sheet.

The balance sheet is, of course, quite a lot stronger than not only it was a year ago but probably a bit stronger than we'd actually expected it to be.

So I expect the discussion to become more live as we go through the year, but we're not there yet in terms of structural cash flow growth.

It's not technically going to be driven by the macro, but the balance sheet has effectively been put in a much stronger place by the macro.

The question on upstream performance in the quarter, there are a few factors impacting but firstly the startup and the [fezaks] costs around $400 million a quarter.

It was less than half that level in the previous quarter in Q4, so a particularly high level of spend in Qatar and in Canada.

In Q2 it's going to remain at a reasonably high level, as well.

Thereafter it should start to fall off.

We'll be up and running in Canada and Qatargas 4 will be up and running.

Hopefully a little bit of performance in GTL as well.

So it will -- that one will start to come back.

There are a couple of other factors probably worth noting for Q1 performance.

Mentioned the downtime from the maintenance around 90,000 barrels a day and also the divestments, and together they effectively relative to last year cost us another $400 million.

Then of course is the 25,000 to 30,000 barrels a day of Gulf of Mexico production that we would otherwise have had had it not been for the moratorium.

Now, that's not the straight reduction, but we would have been drilling and in fact had expected to grow production in the Gulf of Mexico, and so that 25,000 plus barrels a day has quite a significant impact, as well.

So if you put those cumulatively together, I think that explains what we might regard as slightly weak upstream earnings.

We felt that we were reasonably strong at 4.6.

Underlying production was pretty good, and the factors I've just described, none of them were a surprise to us.

Thank you.

Next question?

Your next question come from Theepan Jothilingam from Morgan Stanley.

Please go ahead.

Hi, Simon.

Actually just following up on that question on E&P.

Could you just talk about perhaps the delta on OpEx and increased royalties you're experiencing with the higher oil prices?

And then just going forward through the year, I mean it seems you've had quite a lot of high-margin barrels off for maintenance.

I guess in particular with Nigeria and Bonga, do you expect that to come back on?

Start with the second one.

Yes, Bonga is high margin.

Yes, it was under planned maintenance and I think it's ramping back up again now so it will come back again.

The changes in OpEx, there's a lot of talk about cost inflation coming back into the industry.

We don't actually see that yet, and when we go to market maybe it will come.

If it comes it will likely have more impact on CapEx than OpEx, so our OpEx increases, we will see increased OpEx as we go through the year as we start to incur OpEx in for example oil sands and Qatar.

The unit OpEx once all of those projects are online we expect to go down a bit because actually, and particularly in Qatar, the unit OpEx is relatively low.

Royalties, tax, other increases are difficult to predict.

I gave hopefully clear figures on the UK impact.

Other royalty effects and tax effects is about -- and on top of the UK effect is just over $100 million year-on-year, and it does vary from quarter to quarter.

So not -- I can't project a particular impact there and we just try and manage our way through it.

Okay.

Thank you.

Your next question comes from [Sumat Kaffla] from Macquarie.

Please go ahead.

Yes.

Hi, Simon.

It's actually Jason Gammel from Macquarie.

Hi, Jason.

I just wanted to follow up on a comment that you made earlier about your LNG portfolio having three projects in Australia that essentially would fulfill future market demand.

How do you go about prioritizing the marketing of those three projects, and are -- would any of them be more appropriate say for just taking into your own portfolio versus a long-term contract with a single buyer or a group of buyers?

Thanks, Jason.

Good question.

The three projects you talk about are Gorgon which is already under construction, Prelude which hopefully is close to a final investment decision.

That's the floating LNG project.

And the third one is the CBM to LNG project, coal bed methane or coal seam gas, which is in the Arrow project which is officially a joint venture with Petro China.

Now, Shell's share of production in all three projects is between 3 million and 4 million tons, and so we have about 10 million tons in total of Australian LNG to market.

All of those volumes are effectively to be sold from the project to Shell and Shell will then market to customers.

So in practice we are and have some contracts.

We are seeking more that are not source or destination specific where we sell to the customer and they are indifferent to the source of the LNG.

So we are effectively taking them into Shell's portfolio, and that's why the Australian projects make such a big difference to our overall portfolio because by and large the majority of our existing production is tram lined in from one source to one destination customer.

Does that cover the answer?

So that actually determines how we prioritize.

Yes, it certainly does.

And I guess just as a follow-up would you expect that the flexibility that it gives you would give you the opportunity to capture spot market dislocations like what is going on in Japan right now?

Always, of course, subject to transfer pricing and other issues that always need to be done in a very transparent fashion.

Thanks, Simon.

Of course, just on Japan, by the way, we did not take advantage on price at all.

Everything was done under normal contract prices.

It would have been wholly inappropriate to take advantage of that situation.

Okay, thanks.

Next question?

Your next question comes from Jason Kenney from ING.

Hi, Simon.

Congratulations on the good progress this year so far again.

Thank you, Jason.

So I've got two questions on Brazil.

The first is to ask if you've got anything that you can say about Campos Basin exploration fund Petrobras announced this morning and maybe reminders what is next offshore Brazil.

The second staying with Brazil with the rise in JV, I wonder if you can comment on the Brazilian press article in Valor that suggested that Chairman Rubens Ometto has negotiated a $25 million per annum pay package from Shell directly for ten years there.

Thanks, Jason.

Well, I can't comment on the Petrobras announcement because I haven't actually read it.

Our actual activity coming up this year is you may recall the BMS 54 block last year.

The Gato de Mayo discovery is 80% Shell.

We expect to drill at least a second well this year on that block on what is in effect an independent prospect within the block.

We will need a second appraisal well on both of those prospects before we really know what we have in that particular area.

The BC-10 Phase 2 project is progressing and we will be doing more drilling there.

And we have a couple of other wells being drilled on our behalf by Petrobras that we have.

It's an exciting time offshore for us in Brazil this year.

Right.

And JV reports on Rubens' pay package, this is Rubens' compensation not as remuneration.

It's effectively from the joint venture.

He was a major shareholder or is a major shareholder of Cosan, a big obviously supporter of the deal, not a Shell employee.

No decision yet, either.

It's not necessarily -- it's not really a decision for Shell.

This is a decision for the joint venture.

That's all I can say really.

Okay.

Thanks very much.

Thanks, Jason.

Next question.

Your next question comes from Mr.

Jack Moore from Harpswell.

Please go ahead.

Hello, Simon.

Nice quarter.

Thank you.

A couple kind of big-picture questions.

I was wondering first with respect to service costs, what are your expectations over the next year?

I think in particular one of the large three oil service providers has focused keenly on improving their margins significantly, and I was just wondering how you see your costs escalating over the next year.

And then in the long run what are your expectations with natural gas kind of on a global basis?

Do you see prices more of a global price or do you see kind of pockets where there will be dislocations based on supply and demand in that specific geographic region?

Thanks, Jack.

I'll try and cover it briefly because they're both quite complex subjects.

Service costs generally, as I mentioned, there's quite a lot of talk about potential inflation but we don't actually see much yet when we go to market.

I imagine many of the companies are focused on improving their margins, but you may recall a couple of years ago post the credit crunch, a lot of companies said a lot about going back to their suppliers and demanding reductions immediately, kicking the door down to do so in some cases.

I think you may recall that we didn't do that.

We went back and opened up what we hope was a more construction discussion that said how do we work together with some of our suppliers, including what I imagine are the big three, and how do we constructively manage for the benefit of both of us the way through volatility in the price cycle which is not actually of much help to either of us.

We did come out of that with some what I think was much better improved contracting strategy and supply relationships and agreement that provide both some long-term security of supply for the supplier and for us less volatility in the cost of the services.

They will not provide 100% protection against another doubling or trebling of overall costs, but they will help to ensure that we have access to the services and hopefully getting the [A team] from the service company which is usually the biggest driver of value for us.

A good relationship can have a lot of value.

So we're not seeing that significant a change at the moment and we think that the agreements we have in place with most of our main suppliers will be robust against inflation.

Gas prices longer run clearly we're a gas -- becoming a gas company.

We probably will produce more gas and oil this year, so a very important question for us.

Three different markets.

North America will remain divorced from oil pricing.

It will be driven by supply, demand and alternative uses, so basically we believe at the top end alternative sources of fuel for power.

So we plan on the basis of a range of gas prices $4 to $8 per million cubic feet.

Will a global gas market develop?

Well, not at the core.

That's not our expectation.

At the margin there will be movement to molecules from in maybe both directions, from North America to Asia.

For the Asian market we see medium and long term remaining quite closely linked to oil prices.

In between Europe, that market has shifted already from what used to be 60% oil-liquid related contracts.

Now it's more like 40% with the rest being spotter or hub priced.

That trend may continue.

There is still a market for longer-term oil price linkage depending on the customer's wishes, but of course the spot and the hub price in the past quarter alone were at one point three times higher than the Henry hub price.

So the fact that spot and hub prices may become the norm does not necessarily mean they will be a lot lower.

It's just a question of what kind of volatility and what kind of price arrangement does the customer want.

So we see three markets.

LNG will arbitrage between them, but probably more at the margin than it will do structurally so a very complex situation.

Hope that helped.

And that's very helpful.

My pleasure.

Simon, it's very helpful.

Thank you.

Thank you.

Next question?

Your next question comes from Bert van Hoogenhuyze from [DPB Bankers].

Please go ahead, sir.

Hi, Henry.

This is Bert from the Netherlands.

Hi, Bert.

I was wondering about the upstream profitability.

There was just a very marked jump-up in the Q1 in the area other.

You said Qatargas 4 only gave a small contribution so far, so I wonder this is mainly Russia or has Majnoon already reached some threshold to generate some profits?

Well, I can tell you it's not Iraq, but in essence it's basically higher oil LNG realizations.

We've got -- the other area that you can think of as being assuaged from Africa to be the Middle East through to Russia, so yes, it does include Russia, but it will include the LNG and from the Middle East.

Also from Nigeria, so that's really what's driving it.

Right.

And the second question is you talked about Cardamom.

I understand that as of about ten days ago ten permits had been issued for the Gulf of Mexico.

Undoubtedly you are among those.

Do you have any sort of prediction as to what sort of number of permits you will have held by the end of the year?

Thanks.

This is a good opportunity just to reiterate where we are in the Gulf.

We have eight applications in, including new exploration plans.

We've had two of those expiration plans now approved.

They are as far -- well, one approved and one accepted as complete.

The approved one is Cardamom and the Appomattox plan has been accepted as complete and is now in the consideration period.

They are the only ones so far to have reached that complete stage, so that's for new wells.

The Cardamom first drilling permit was issued.

We started drilling three weeks ago, so we are actually drilling exploration wells in the Gulf of Mexico now at the Cardamom prospect which is good news.

Separately we've also had approval for one of the Perdido development wells which we are also about to drill.

We've got five floating drilling units and we are drilling off some platforms work such as workovers and recompletions.

Of the floaters that we've got, three of them are already new regulation ready and one is close.

And the other one we've taken down to Brazil for a while.

So we are getting back to work, but it is still slow progress.

We said we expected to lose effectively 50,000 barrels a day of production this year in the Gulf relative to what we otherwise would have achieved if there had been no moratorium.

The rate at which we're coming back, we stick with the 50,000.

We don't change that, but we would like to see the rest of our applications progressing through, as well.

But it's good to see that there is forward progress and that we are able to start drilling again.

Thanks very much.

You've been very helpful.

Thanks.

Next question, please.

Your next question is from Iain Reid from Jefferies.

Please go ahead.

Hi, Simon.

Hi, Iain.

Two quick questions.

The provision you made for the UK tax price seems pretty small in relation to your size and certainly a lot smaller than your UK competitor announced yesterday.

Is there some sort of tax relief there or kind of a different treatment do you think you're applying there?

And secondly on Qatar I just wondered if you can remind me of what percentage of the LNG volumes are long-term contract linked to oil from there.

I'll start on the second question, and we've not actually given a figure.

We've just indicated in the past that originally half the volume was targeted at North America and half at Europe.

And Qatargas does the marketing and they're doing an excellent job in redirecting not just short term but long term, as well, that gas into Asian markets and the Middle East itself.

So we are in effect seeing quite an uplift compared to what we would otherwise have got had we been exporting into North America.

The exact proportion is evolving as those contracts are being put in place by the Quataris, but we're very pleased with what they've been able to achieve so far.

And the UK tax provision is an interesting one.

We had to work a bit on this.

We haven't taken a provision yet.

The provision that we take, the big change will be next year in the first quarter.

The reason we haven't taken the provision is basically the impact is the deferred tax liability that we carry as a result of capital answers being different to depreciation and the deferred tax asset that we carry that reflects a future decommissioning liability.

If those two are of a similar size, which in our case they are, the change in tax has no -- or little or no net impact which is the case for us.

They are very similar in size and no material net impact in the first quarter.

If, in fact, that liability and asset are of a different size, yes, you would get a one-off impact up or down in any given quarter.

So I can't speak for others, but that's what our situation is.

There of course is then an uplift every quarter of the current tax.

The next year's provision in Q1 happens when effectively we've increased the deferred tax assets on the retirement obligation from the 50% to 62%.

When the legislation is enacted, which is likely in Q1 next year, we'll have to reduce that from 62% to 50% and that impact is likely to be around $500 million.

A bit complex and technical but hopefully that helps.

Yes, thanks very much.

Thanks, Iain.

Your next question comes from Lucas Hermann from Deutsche Bank.

Please go ahead.

Yeah, Simon, afternoon.

I hope you're well.

I could have a laugh and ask you to repeat those last comments but I think we'll move on.

Just a couple of questions if I might.

Firstly, can you talk a little bit about CapEx phasing?

The CapEx this quarter including associates looks very modest relative to the guidance.

And secondly I wonder if you could talk a little more around the chemicals operations where if I look at cracker margins they're very high and yet your profits are heading -- well, have come back modestly.

And in particular what's happening with Bukom and why Bukom down for such an extended period of time.

Thanks, Lucas.

CapEx phasing, yes, it was effectively quite low.

We gave an indication and we retained the same indication that we would likely spend this year $28 billion on organic investment and $2 billion on acquisitions, and the $2 billion was the completion of the Reizen deal in Brazil.

So the going rate would be 7.25.

The actual rate in Q1 was around 4.

Couple of issues really.

One is just typical phasing particularly in the downstream tends to be back-ended and you can see that in the downstream CapEx figures.

Secondly, on the upstream we are seeing the CapEx coming off on some big projects.

And while we expect to take some new FIDs, they're not all taken yet so I would expect on the bigger FIDs that we'll -- some of which I've mentioned earlier, they will see an uptick in the upstream expend as we go later through the year.

On the chemicals margins, yes, Asia was the main challenge for us where potentially we could have done better.

The issues at Bukom were just basically related to the startup of the plant and still working to optimize the performance there, so no real comment on the underlying issues.

Hope to be back up and running in the not too distant future.

I mean, Simon, is $28 billion in CapEx a realistic number for you now?

Do you mean annually or this year?

Well, I mean this year, yeah.

And if you could tie that in with your thoughts on US gas expenditure, as well.

I reserve judgment on whether it's realistic.

We'll have to try quite hard I guess to spend on that rate on organic, particularly the other point that you raise on US gas.

We have stated in the past we've got the portfolio expense somewhere between $3 billion and $5 billion per year on this activity.

Typically our investment -- the strategic plan looks at something in the middle of that range.

It's likely or certainly early planning is more at the bottom end of that range while the oil -- the gas price stays at $4.

But there is still quite some potential on the liquids, or the more liquids-rich part of the portfolio.

And just on the FID, things like Prelude, Cardamom and the two UK projects, [class gallion] and the Athabasca debottlenecking, they all started to take up the slack fairly quickly as we get into the second part of the year.

Thanks very much.

Okay, thanks.

Moving on to the next question, please.

Your next question is from Mark Gilman from Benchmark Company.

Please go ahead, sir.

Simon, good afternoon.

I had a couple of things.

I think one of the slides indicates that in the first quarter you acquired some additional Rockies and Marcellus acreage.

Wonder if you could quantify that both in terms of acreage and cost.

Would also appreciate some commentary on what the Americas unconventional gas production looked like in the quarter and how it compared to prior periods.

Thanks, Mark.

We've picked up a little bit more acreage in the Marcellus and around the North American plays, but it's not been that material in terms of what we're picking up, relatively underdeveloped should we say so we're not paying top dollar.

The unconventional gas production, during last year we grew to 1.2 BCF a day by the end of the year, and of course we're now seeing the impact of the investment in South Texas so we're back just above a BFC a day or 180,000 barrels a day oil equivalent.

So it's dropped back again, but we expect that figure to grow as we go through the year, particularly out of Haynesville, Grand Birch, and laterally into the Marcellus.

Okay.

Simon, if I could, I was confused by your comments during your direct remarks on the UK tax impact and why the 2012 100 million per quarter number ostensibly at the same price level was so much higher than what you envision for the balance of this year given the March 24th effective date of the increase.

That's partly a pickup in the expected profitability in the UK.

Just a factor of a variety of issues, production, prices, etc., but that is how it is so it's an average of 100.

Okay.

Thank you.

Thanks.

The next question, please.

Your final question comes from Alejandro Demichelis from Merrill Lynch.

Please go ahead.

Yes.

Good afternoon, Simon.

Just one quick question on the Gulf of Mexico.

You mentioned the situation about the barrels and the 50,000 target still unchanged, but in terms of cost what we can see in terms of you coming back and drilling again there?

Is it going to be any kind of reaction on cost there?

Thanks for the questions.

Good point worth noting, and we did --actually did take another $60 million in the first quarter on cost.

As we go forward the cost impact is primarily in capital and not OpEx.

The new regulations as we see them and interpret them, we don't expect to add material cost as by and large they reflect the practices both in design and operations that we were already applying.

The unknown factor is that quite a lot of the reports that have come out to date contain recommendations.

They don't actually change the legislation yet, so it's possible that the regulations still have some room to develop.

We're also not entirely sure how some of the regulations will be interpreted.

It is possible that some of them will make it take longer to drill a well, and we'll still be paying the same spread rate and it could be a million dollars a day on a rig plus the support activities.

So that we don't know yet because we need to get a big more experience, but by and large as the regulations are drafted, they reflect practice in for example Europe and the standards that we were already applying.

Great.

Thank you.

Thank you very much.

And I think that's it.

Operator, is it, no more questions?

You have one final question from Sergio Molisani from UniCredit.

Okay.

Thank you.

Last question.

Thank you.

Yes, good afternoon to everybody.

Two questions if I may.

The first on the Pearl GTL, on the occasion on the Qatar (inaudible) you gave a sort of guidelines for your very (inaudible) from Qatar based on the price scenario $50 to $70 per barrel.

And if I remember well the guidance was $3 to $4 (inaudible) more or less until 2020.

Can you give us an idea of what could be this cash flow on a (inaudible) per barrel oil price scenario?

And the second question is on CapEx.

Your $28 billion guideline includes so it's gross or net of the (inaudible) $1 billion of (inaudible) cost that you guided for considering that if I understand well these are startup costs or investments that you are not allowed to capitalize spending the startup of this project?

Thank you very much.

Thanks.

I'll take the last question first.

The $1 billion is OpEx.

It's not part of the CapEx so it's -- the $28 billion is separate and is genuine investment activity.

On Pearl GTL you are absolutely right in your memory.

$3 billion to $4 billion at $50 to $70, or without incentive the $70 is $4 billion of cash flow per year, and that's both projects, not just GTL but Qatargas 4 as well.

We've not given any update at the higher oil prices mainly because we don't necessarily expect them to stay at $120 for long enough for it to be a sensible discussion.

So I can't really to be honest give you an additional factor, but hopefully it's good that we can confirm the $4 billion at $70.

Thank you very much.

I think that's all the questions we have today.

Thank you for those questions and for joining the call today.

The second quarter results will be released on the 28th of July.

Peter Voser, Chief Executive, and I will talk to you all then.

And finally I'm sure that everyone here at Shell and hopefully many of you on the call would like to wish the royal couple all the very best luck for tomorrow and for their future relationship.

Thank you for listening.

Good afternoon.

That concludes the Royal Dutch Shell Q1 results announcement conference call.

Thank you for participating.

You may now disconnect.