殼牌 (SHEL) 2010 Q1 法說會逐字稿

Welcome to the Royal Dutch Shell Q1 results announcement call.

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

(Operator Instructions).

I would like to introduce our host, Mr.

Simon Henry.

Thank you operator.

Good afternoon and good morning to those in the US.

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

Let me take you through the results in the portfolio developments for the first quarter and we will leave plenty of time for your questions.

Firstly, could you take a moment just to read the definitions of the cautionary note.

Our CCS earnings, Current Cost of Supply earnings, actually the identified items for the quarter were $4.8 billion.

That is an earnings per share increase of some 61% from the first quarter of 2009.

Our results have stepped up from last year, and profitability has certainly increased from the low levels that we saw in the fourth quarter of 2009.

This year-over-year improvement has been driven by higher oil prices and higher chemicals margins, but that is combined with increased sales volumes and thus as a result of our operating programs, our operating performance and our growth programs.

These are better results from Shell, but we are not relying on economic recovery or seasonal effects from here on in.

The macro environment will be what it will be.

We continue with our focus on growing our cash flow, underpinned by new projects and lower costs.

Back in March, we outlined our strategy for the next several years.

We are working on improving our near-term performance, delivering a new wave of growth into 2012 and maturing the next generation of projects for growth for 2013 and beyond, and we have made progress on all three of these themes so far this year.

We have successful start-ups at two new projects in the quarter.

Deep water oil and gas production in the Perdido platform in the Gulf Mexico, and new ethylene capacity came on stream in Singapore.

We are delivering on the downstream asset sales in what is still a difficult environment with an agreement to sell our New Zealand position.

We are making good progress against our target to reduce costs by $1 billion by 2010.

We are abetting a culture of continuous improvement, commerciality and cost control in our day-to-day activities.

Looking to the longer term, we are building on our 2009 expiration success with new discoveries.

And we have taken up new gas positions in China and Australia and in Brazil by a new joint venture which includes, of course, more downstream potential.

Overall, it is a good start to 2010.

Let me give you some details on performance in the quarter.And I will start with the macro environment.

If you look at the macro picture compared with the first quarter of last year, the oil prices were significantly higher than the $44 a year ago.

Brent averaged $76 a barrel.

Actual gas prices increased in most regions but were slightly lower in Europe.

The industry refining margins were significantly lower than year-ago levels.

That's in most regions, although refining margins did improve from the fourth quarter of 2009 and they were supported in this by a high level of industry, downtime to maintenance in the first quarter.

The chemicals margins increased in all regions compared to the first quarter of 2009, with the most pronounced improvements coming from Asia and Europe.

So it is a pretty complicated picture overall.

But some [track] is up and some down.

But overall, the trends were positive for us in the quarter.

Turning now to our earnings.

The earnings for the quarter did include identified one [off] items of $75 million.

Excluding those items, the current cost of supply earnings were $4.8 billion, and the earnings per share increased by 61%.

That's compared with the first quarter a year ago.

The quarter was characterized by higher earnings in upstream and a decline in the downstream.

That is mainly a result of higher oil prices and chemical margins, the higher volumes in the upstream, and the lower refining margins in the downstream.

The cash flow from operations for the quarter was $4.8 billion, but excluding the net movements in working capital, was just over $10 billion.

Now, let me talk about the individual business performance in a bit more detail.

Firstly on the upstream.

The upstream earnings increased by 132% to $4.3 billion in the first quarter of 2010.

The higher oil prices, the higher oil and gas production and the higher LNG sales volumes were the main drivers in the upstream results.

And these are partly offset by the lower realized gas prices in Europe.

Some of you have asked to see our gas realizations including our large affiliate Company in the Netherlands, the NAM.

We have now included the NAM realizations in the European information in the supplementary tables for you to use.

And hopefully this helps you with your modeling.

On that basis, you will note that the European price went down year-on-year.

The upstream production increased by 6% first quarter to first quarter, and we reached some 3.6 million barrels of oil equivalent per day.

If you set aside what we call uncontrollable factors, things like the OPEC quota, the weather, and look at the underlying performance, then the barrels from the new fills and ramp-ups contributed some 200,000 barrels of oil equivalent per day and that more than off et the 150,000 barrels a day [and back] from the natural field decline.

Our LNG sales volumes grew by 38% first quarter to first quarter and over 4.2 million tons in the quarter.

That's our highest volume ever.

That is driven by increases from Sakhalin II in Russia and from Nigeria LNG where we had a limited restart at the [Soku] gas plant and that improved the gas supply picture for Nigeria LNG.

Looking into the second quarter, while the weather-related gas sales added some $200 million to Q1 earnings comparison, this is unlikely to repeat of course in the second quarter.

Let me also remind you that we have [Athabasca] oil sands project in Canada that produces between 70,000 and 80,000 barrels per day for Shell.

That went ito a planned shut down, a significant turnaround in mid March and that will restart again in June.

We are also expecting some Q2 downtime in the Gulf of Mexico on a planned basis, in fact that was in April, and some operational issues in Nigeria.

So overall in the first quarter, much better earnings performance from the upstream.

But we are in a delivery window particularly for the group with a sequence of 13 new projects, 12 of which are in the upstream and they will come on stream in 2010 and 2011.

These projects underpin the cash flow and production growth targets for 2012 that we discussed back in March.

And last year's start-ups, Sakhalin in Russia and BC 10 in Brazil deep water, they've both had very successful ramp-ups, contributed to Q1 uplift of around 120,000-barrels of oil equivalent per day.

Both of these projects are currently producing above the planned expected levels.

In the last few weeks, we've had a successful start-up of Perdido in the Gulf of Mexico.

A reminder that Perdido is the industry's first production from the Lower Tertiary reservoirs in the Gulf of Mexico.

This [spar] development is expected to produce around 100,000 barrels of oil equivalent per day in some 2.5 kilometers of water depth.

This really is a high-tech first development, with many industry firsts incorporated in the design.

More importantly, I expect this to be a highly profitable hub development with additional growth potential in the future as we have now developed that new infrastructure in the region.

The next sweep of start-ups includes the mine expansion in Athabasca in Canada and our two gas projects in Qatar.

These projects remain on track and they will underpin our growth across 2011 and 2012.

Turning to the downstream earnings, in contrast to the upstream where we had the large increase, the downstream earnings declined by 36% compared with the year-ago levels to $0.8 billion.

This decline was due to losses in refining, a low contribution year-on-year for marketing and trading, partially offset by a strong earnings in chemicals.

However, we [pointing out] that downstream earnings have rallied somewhat from the low point we saw in the fourth quarter of 2009 at the back end of last year.

So starting for a change of chemicals.

The chemicals earnings have improved from a loss making position a year ago.

This is due to the shift to more flexible [feed stocks] in our Gulf Coast portfolio and to more favorable market conditions worldwide.

In Singapore the new chemicals plant, which is integrated with the [Bucon] Refinery, it came online in November last year with the mono ethylene [glycol] production, and the main ethylene [crack of] production started there at the end of March this year.

The first quarter 2010 chemicals earnings were pretty close to the full performance in 2009 and it is good to see that.

In refining, the industry conditions were sharply weaker on a Q1 versus Q1 basis.

But we did a reduction in the losses compared with the fourth quarter of 2009.

Our first quarter refinery intake, it fell by some 5% as a result of weak demand and turnaround.

The first quarter of 2010 also saw an unusually high level of maintenance downtime in our refineries, and our availability was 89% versus a 92% availability a year ago.

The market and trading earnings, they decreased from a year ago levels when we benefited from parachute affects from the falling oil prices that we saw in that quarter.

However, marketing earnings, they did increase from the fourth quarter of 2009, returning back to more normal levels with higher earnings from from retail, from lubricants and from commercial fuels.

Overall, through the last couple of years of [digital] market environment, our marketing portfolio has been pretty resilient in the face of that tough environment.

So, those are the earnings.

Turning to the cash flow and the balance sheet.

The upstream and the downstream cash inflows and outflows have been brought in balance over the last 12 months.

However, we have been running a cash deficit at the group level as we have used the balance sheet to maintain the growth spending programs, to top off the pension funds and to pay an attractive dividend.

I'm pleased to see the cash flow from operations, excluding those net movements in working capital, reached $10.4 billion in the first quarter, more than double the cash flow in the last quarter of last year.

However, we have continued to increase borrowings and this will likely continue in 2010.

The balance sheet [gearing] was 17.1% at the end of the first quarter, a slight increase from the end 2009 levels and around the middle of our guidance range of 0% to 30% of gearing.

So we watch the cash position and they balance sheet very closely, and we are putting particular emphasis on costs and capital discipline within the Company.

We reduced Shell's underlying operation costs by some $2 billion in 2009, and we're on track to deliver a further $1 billion of the underlying cost savings in 2010.

This will come from head count reduction, around 2000 positions in 2010-2011, in addition to the 5,000 staff reduction we saw in 2009.

It will also come from simplifying and standardizing our activities and help to reduce the supply chain costs that form such a large part of our total cost base.

So we've made progress here, and there is clearly more to come.

Let me update you on portfolio developments.

And there have been quite a few of these here in what has been a rather busy start to the year.

Exploration made three new discoveries and drilled a successful appraisal on the 2009 [Perdido] Discovery, all of those in the Gulf of Mexico.

2009-2010 drilling to date has delineated over 350 million barrels of oil equivalent resource for Shell in the Gulf Mexico.

We continue to evaluate these discoveries.

We are looking at options to fast track the development of these exciting new finds with over 150,000 barrels per day of oil equivalent production potential.

Elsewhere in the world, we built up new gas potential in the Asia Pacific region with tight and shale gas acreage additions in China and the bid for the coalbed methane to LNG player, Arrow Energy, in Australia.

This is a joint [bid] with PetroChina and still obviously subject to final approvals.

In the downstream, we announced a potentially $12 billion memorandum of understanding with Cosan, a Brazilian company, to create the joint venture for our Brazilian activities.

That is both downstream and ethanol, sugar to ethanol.

We will work with Cosan on biofuels growth.

On the disposal side, we completed the divestments of our New Zealand downstream activities and we have agreed to sell three production licenses in Nigeria to a domestic company subject to government approval there.

We have also announced a review of 21 downstream countries in Africa as part of our plans to exit from 35% of the number of retail markets we are present in by the end of 2012.

These positions, they can be profitable, in fact they are profitable in their own right, but we want to focus on scale in our own operations.

So as you can see, we have been pretty busy on the portfolio side already in 2010.

Let me summarize, and then we will go for questions.

I am pleased with the performance in the quarter despite a difficult environment.

We are in that window, the delivery window for new growth.

We are making progress on the strategic themes, the shorter-term performance focus, the delivery of the growth projects and the generation of the new investment options.

At the same time, we are keeping an eye on the medium and longer term.

We are picking up new assets on a very selective basis, and continue to invest at relatively high levels for more[exploration] barrels.

The priorities are for a more competitive performance, for growth and for sharper, more focused delivery of strategy.

By taking these steps, each of which, you can see, appears in the Q1 results, we are bringing our Company and shareholders into a period of production and cash flow growth into 2012 in pursuit of the targets we discussed in March.

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

It would be good if we could restrict ourselves to a couple each please so that everybody gets a chance.

Operator, please could you poll for questions?

Thank you.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions).

Our first question is from Michele Della Vigna from Goldman Sachs.

Please go ahead with your questions.

Hi Simon.

It's Miclele here.

I have a couple of questions.

The first one is, in Nigeria you have seen big improvement in Q1.

Are you seeing any further improvement now in April?

And what do you expect at this point for the full year?

And also related to that, you have not upgraded the guidance for production 2010 despite a strong Q1.

What are the key answers that you need to list before being able to do that?

Thank you, Michele.

Good question on -- the two answers are related, as you might expect.

Nigeria in Q1, yes good performance.

Offshore, we are running at relatively sustainable levels that we expected.

Onshore we did well operationally in two areas.

One was the [Soku] gas plant where we have been up and running for most of the first quarter, and we also have brought on stream the shallow water slightly the offshore [EA] producing unit.

It is a floating vessel.

They both performed well in Q1.

They drove the increase of roughly 80,000 barrels a day in the Nigerian production that we saw in the first quarter.

The EA platform is currently down for maintenance again in the second quarter, and Soku has some issues getting liquids through the systems so [inventory has been impacted.] In fact, although we ramped up well in the first quarter, both of the two projects that actually helped us to do that are currently either not producing or producing at low levels.

That's difficult to sustain.

The rest of Nigeria, clearly the usual intent is [applied], but it is not -- there have been worse quarters and there have been better quarters.

2010 production guidance, just to remind, our actual production in 2009 was 3.15 million barrels per day oil equivalent.

Our stated guidance was to be broadly flat in 2010.

We obviously take into account the fact that our production is obviously quite seasonal.

Q1 and Q4 are typically high production quarters, largely driven by European gas demand when it is cold and and Q2 and Q3 are sometimes impacted by planned shutdowns in the North Sea in particular and in Q3 by by hurricane activity in the Gulf of Mexico.

We cannot project forward 3.6 million barrels per day.

I did mention oil sands downtime.

We also have had a few weeks out in the [Marversa] corridor for planned maintenance in April.

Quite a few factors already affecting the second quarter production.

It is true, of course, that having 3.6 million barrels per day in the pocket from Q1 is a help.

But given the uncertainties I have run through, it is a bit early to be projecting that we will end up ahead of our expectation for the year, but it is a good start.

Thank you.

Thank you.

Our next question [Allejandro Bermashellis] from Merrill Lynch.

Please go ahead with your questions.

Good afternoon, gentlemen.

A couple of questions here fro me.

The first one is on the downstream segment, how do you see that going forward?

We are still seeing some drops in refining.

When are you expecting that to change?

The second question is in terms of the disposal that you have been talking about.

When is is that you are expecting to close those?

Thank you, Allejandro.

The downstream environment in the first quarter, the oil refining margins recovered from the previous quarter.

They are still fairly difficult and they are difficult for two reasons.

One, lack of demand recovery particularly in the West, in Europe and North America.

And secondly because that very very significant Asian supply new refineries that came on stream during last year and two million barrels, have [reasonable] capacity additions.

It is still an [overhand].

Asian margins, despite the growth and demand, are still impacted by quite the significant new capacity.

On Q1 in particular, there were a lot of planned turnarounds or maintenance activity, including our own.

And that did help underpin refining margins in both North America and Europe.

If anything, it was probably a bit of downward pressure in refining in the short-term.

Medium term, it is driven entirely by the factors that I referred to, the demand growth or lack of in Europe and North America.

We don't yet see sustainable improvements there.

The last factor worth noting is that stocks typically remain relatively high, particularly stocks of distillate, and Shell in particular has a refining configuration that is distillate heavy.

That is something we need to work to [stop] in the system first.

The chemicals have picked up a bit year on year for sure.

Still a little early to say if this is a real sustainable demand improvement.

But we're quite pleased.

We have actually improved our margin position in Americas from more gas feed stock and we are well positioned for that Asian demand growth.

The marketing and trading business returned more to its typical level somewhere between $0.5 billion and $1 billion a quarter as typically what we have seen, and we are towards the upper range of that in the first quarter.

The disposal program, we have talked about both marketing and refining disposals.

The marketing disposals we are continuing to progress.

We completed New Zealand in the quarter.

There is still a lot of interest around the world in different markets that we look at.

The refineries, obviously the European refining market is not an easy one to sell refineries into at the moment.

We have been talking to [SR about] three European refineries.

And that's [Stanlow] in the UK, [Hyder and Harburg] in Germany.

Those negotiations are probably taking a bit longer than we would have initially hoped.

We are talking to potential other buyers.

But we continue with SR and we are still hopeful of reaching an agreement there.

Will will, of course, not enter into a fire sale of assets.

We've been clear about that all along.

And if we have to consider either closure or moving to a terminal operation, that's what we will do.

Take the next question, please operator.

Thank you.

Our next question comes from Neil McMahon from Sanford Bernstein.

Please go ahead.

Hi Simon.

I've a few questions.

The first is really on the strength of the realization in the upstream business.

Could you tell us [whether] this is skewed to any [like] effects that may have been from picking up from some crude sales from last year.

And also, if it was due to any strength in the LNG pricing, given the fact that you have increased so much LNG volume with Japan and Korea and other places seemingly having strong LNG demands over the winter.

And then just a quick second question was on some of your key exploration wells over the next six months, especially those in the Arctic.

Could you give us sort of timing of when we would be expecting those wells to be drilled?

Thanks.

Thanks, Neil.

I think you meant oil price realization.

Let's start with gas price realization.

What we saw in the first quarter of this year was the flip side of what we talked about in Q3 and Q4 last year.

Gas prices, even where they are oil-price linked, are particularly lagged.

So we did see some strength in those markets.

That helped obviously in LNG pricing.

It was also a particularly cold winter in Europe, bitterly cold in northeast Asia and fairly cold in North America as well.

So spot LNG pricing was relatively attractive too.

That helped the realizations through the hole of the portfolio.

There is some linkage.

On oil price realizations there is nothing particularly specific to talk about.

It is just the timing, timing of cargoes.

No specific issues behind what you see.

It is just a mix of what we were selling.

The key exploration wells, good question.

Where are the key exploration wells?

The priorities are for a more competitive performance (audio skips here) [to] probably start.

We are drilling in the Gulf of Mexico, follow-up wells on the discoveries that we have had, particularly in the eastern Gulf around the Appomatox discovery, three follow-up wells over the next 12, 18 months and spotted later this year.

We have a couple of others elsewhere in the Gulf later this year as well.

In Alaska, the situation at the moment is, we are good to go in terms of the permits that we have in hand.

But obviously, it is a legal environment where not everything is under our control.

We have seen these uncertainties before.

But at the moment we are planning to drill.

It is not likely that we will [spud] before August.

We are making the plans and preparations [in turn], and we have got the logistics and support in place that drill.

We haven't yet decided whether we drill [Chuckchi] or [Botha], they are different plays.

But the intention is that we will drill at least one of them this year.

And if we can, we will fit a couple of wells into the window.

It's a three, three-to-four-month window and we will update obviously as we go forward what our intention is.

The other key well is clearly Brazilian [subsea] the BMS54 block.

We have 100% block there.

We have got two prospects identified.

We will spud -- the intention is in July, the first prospect.

Most likely we won't drill the second until next year because we would like to look at the results.

of the first well there.

But that is 100% Shell.

Santose Basin [presold].

Looking forward to that.

Great, thanks.

Covers everything?

Move to next question.

Thanks, Neil.

Thank you.

Our next question comes from Lucy Hoskis of Barclays Capital.

Please go ahead with your questions..

Good afternoon Simon, and great session on [this.] Two questions please.

The working capital movement, it was a big such charge this quarter, sort of unusually so relative to what we normally see at 1Q.

I wonder if you have any color on that.

The second was on DD&A guidance, because I think in the past you've typically been talking about a rising trend.

But did the reserve bookings of 2009 actually start to change that picture?

Thanks, Lucy.

Thanks for the acknowledgement.

Working capital $5.5 billion negative movement in Q1.

A little unusual but not that unusual in this cyclical industry.

Some of this reflects inventory increases in the downstream price and a bit of volume.

The prime driver is additional working capital allocated to the trading business.

During last year they were playing [contango] positions as I'm sure you're aware.

During the fourth quarter they closed quite a few of them.

They closed them [down] to realize the value.

As they opened new positions, the cash impact just moved into this year and their actual inventory level was not much different at the end of the first quarter to the end of 2010.

So it is just temporary timing effects.

I would also say this is working capital which is not tied up for years.

We keep a pretty close watch on this.

It's part of our balance sheet management.

You can see the marginal rate of borrowing, we are likely to get a rather better return than that by using it in the trading business.

So that's the prime driver.

DD&A guidance.

Yes, overall it rises with new projects and that's why we give the general guidance that over time, unit DD&A is likely to grow.

Of course, it does come down through the lifetime of the project, as you prove up moe reserves associated with a given project.

And yes, you are absolutely right, the fact that we added three-plus billion barrels of proved reserves at the end of 2009 has a direct arithmetic impact on our depreciation rates in the year as we go forward.

I won't be able to give you a very specific forecast going forward, but Q1 is relatively clean in that respect in terms of the depreciation in the upstream.

What we will see, of course, as we bring, for example, Perdido online, the Athabasca oil sands online, it is likely to go back up again.

Thanks.

Thank you.

Our next question comes from Irene Himona from [XM/BMP Powerba].

Please go ahead with your questions.

Hello Simon.

In the first quarter, your dividend cover was over two times.

You had free cash flow excluding working capital and gearing was modest as you highlighted.

Under the newly introduced dividend policy, what exactly has to happen before the Board contemplates a dividend increase?

Thank you.

That's a good question, Irene.

I might put the question to the Board.

Fundamentally, we said the new policy -- of course, we aim to grow earnings and cash flow through the cycle and the dividends to grow accordingly.

There are clear issues over the next one to two years that we talked about in March, where if refining, gas pricing and oil prices were to be at the lower end of the cycle, we are spending more than we are earning.

In those circumstances, it is probably not prudent to be increasing the dividend.

So fundamentally, I think you probably recall, we indicated 2010 dividend flat.

We also talked about the potential introduction of the script dividend.

And we will review as we go forward and see the big projects deliver.

I really think the trigger will be big projects kicking off, ramping up, and showing that production growth towards 2012.

And of course the big machines won't really be ramping up until next year.

Which is why we gave that indication for 2010.

So to really be successful, project delivery will be the straight answer.

A short burst of higher prices will probably not do it.

It is the underlying cash flow that really matters.

Hopefully that is good guidance.

Thank you.

Thanks.

Thank you.

Our next question from Joseph Tovey of Tovey and Company.

Please go ahead with your questions.

Good morning, brilliant results for the quarter which you don't need me to tell you.

Absolutely delighted.

I was rather wondering, given that your Company is relatively more exposed to natural gas than some of your competitors, does the increase in unconventional gas in the United States and the application of some of that technology to Europe and possibly other areas put any question in the forecast with respect to LNG growth and the margins in LNG?

Thanks Joseph.

Thanks for the acknowledgement.

Good strategic question for the long term in terms of positioning.

The US growth in unconventional gas hasn't [decidedly] changed that market from being a potential importer of LNG where LNG may have been linking US gas prices to the rest of the world.

We see that as an island market but still a very attractive one.

We have built a very strong position onshore in the US to play that.

We talked about [20 Tcf] and very significant growth potential in our March meeting.

We have $4 to $6 break-evens on the portfolio.

We have got good business potential to make it better.

Your question, I think, is primarily about the rest of the world.

Yes.

Yes, there is potential for unconventional tight or shale gas in Europe.

We don't see it developing as quickly in Europe for a variety of reasons.

One is just the infrastructure.

There are 65 onshore rigs operating in all of Europe at the moment, compared to the thousands you can rustle up in a few phone calls in the United States.

That plus pipeline infrastructure, plus planning and environmental, and the fact, that to be honest, we don't see the geology as quite so [prospective] either.

It means that a Although there is potential.

There won't be short-term a large factor.

One of them we are established as a player now.

coalbed to LNG, the bid for Arrow Energy with PetroChina, clearly is a name to play that into the LNG market.

And the fact that we are doing it with PetroChina, although we have not confirmed, it is quite likely we will take some of those LNG volumes to China and a very good business opportunity for us.

The unconventional gas opportunities in China we do see as potentially very significant, which is why we're delighted to get the two 4,000 square-kilometer each blocks in China in partnership with PetroChina for exploration and appraisal.

We do think it will impact the overall gas market.

But medium and longer term, we see strong demand for LNG long-term contracts into, amongst other places, China as well.

But Japan and Korea are the typical customers, still strong interest and we are negotiating out good volumes of LNG supply that we potentially have, particularly from Australia at the moment.

So it is a factor, not that big in Europe.

We don't see five to ten years.

But further out, the balance in Asia will be largely driven by Chinese gas demand where we see all the signals being fairly positive.

Hopefully that covers --

That does indeed.

Thank you very much.

I did have one other question which is maybe a trifle pie in the sky in that it is politically driven.

There is clearly some problem with respect to the future of the European currency system.

How do you see that impacting upon, number one, any accounting write-offs that might need to be taken, any changes in lives of assets or in the other write offs that might fall into the DD&A category.

And also in terms of currency exposures in the hedging that might be applicable to them to the extent you can comment on it, obviously without giving away strategic information.

Interesting question which I'm really not [thoughtful] in terms of the impact on carrying value of assets.

We are a dollar driven Company.

Our revenues are in dollars, and many of our customers are in Europe.

So arguably, a weaker Euro is good for us.

Of course, a weaker Euro, it it were to impact on the European economy generally, given that we still have very strong businesses in Europe, would have some indirect impacts.

In terms of direct exposures, it is difficult to say what they might be.

It is really the underlying economic exposure to the performance of the European economy that is a potential concern, but I would say, to rather more than just Shell.

So I will probably leave it there.

Difficult to speculate.

Okay?

Thanks.

We'll go to the next question please, operator.

Thank you.

Our next question comes from Burt Van Hogenhauser from VBP Bankers.

please go ahead with your questions.

.

Yes, thank you.

Good afternoon, Simon.

First question on the gas prices Europe ,which apparently held up quite well in view of the strong winter also That happened in Asia.

How do you see gas prices going forward the rest of this year, also in view of the ratio between spot prices and contracts?

And the second question is about [Iraq] efforts in Majnoon.

Will you [count] -- I understand you are already started there and we will have some production next year.

Will you show those production figures in the total production?

Thanks, Burt.

The gas pricing in Europe, I will basically reiterate what I said in March.

There is not a lot to update.

Typically, we are 60% oil-price linked, 405 spot price in Europe.

The particular market conditions in Q3, Q4 last year, plus the fact that the contracts have some inherent flexibility meant that in Q4 we switched more to 40% oil linked and 60% spot.

And that carried on through most of the first quarter.

The one thing that is relatively new is we have been relooking at any re-negotiation clauses with quite a bit of our longer term customers.

And we've done several deals which confirm that most customers are very interested in longer term linkage to oil prices and contract volumes as opposed to spot volumes.

And so we have traded off longer or extensions in the longer term that are oil-price linked against greater flexibility to spot prices in the short term.

You will have seen that.

Actually, spot prices in Europe were reasonably firm, mainly because of the very cold winter during the quarter.

It worked in our favor in that sense.

Majnoon.

Good question.

What we are currently focusing on is that first commercial production.

We have to get the production up to 175,000 barrels per day from its current 45,000 before we really get any return, volumes or cash.

Thereafter, we will be looking at the major field development plan which would consume significant investment but also produce significant cash flow back to Shell as a result.

As we get to the point of recovery, our expenditures beyond first commercial production, we do expect to recognize production and that will be done effectively like a production sharing contact.

We divide the -- our commercially available share of revenues by the prevailing oil price to get the number of barrels produced.

It is very similar to the PSC.

A small amount was included in the 2012 target, because we do expect to reach our target by 2012.

Looking out beyond it is difficult to say how much volume we are talking about, because we haven't yet defined the scope, and particularly the pace, of the second level of the major field development.

We should take the field itself up above one million barrels a day of production.

So relatively small spend in the first couple of years, no volume until 2012.

We will recognize volume thereafter but it will depend on the pace of the development.

So hopefully that is clear

Great, thanks very much.

Very small follow-up on the gas one.

Do I basically understand that you have basically 20% flexibility between spot and phased contracts, long-term contracts?

That's the way it works, but the amount of flexibility in the contract goes down during the operational year, which typically starts in the first of October.

They are not all the same, but it's a general rule, if you take all the flexibility in the first quarter, you have got rather less left for the next three quarters.

Okay, thank you very much.

Let's move on to the next one.

Thanks.

Thank you.

Our next question comes from Jason Kenney of ING.

Please go ahead with your question.

Hi Simon.

Good set of results.

Well done.

Thanks.

On the LNG business, which I think accounted for over $300 million of the [beat] in earnings to date, Still a bit of a black hole for forecasting.

I was wondering if there was a case for increased disclosure or better guidance on [EBITDA] in the LNG business?

I know from your full-year results, tha the producing activities in the upstream give one number, and you have a reported upstream number.

And there was some implication that gas and power and midstream obviously make up the rest.

You are not at risk of having that LNG business undervalued if we don't see better disclosure?

No, I think we are perhaps the only one of the majors that actually splits out the LNG business in this kind of way to show the integrated earnings.

I think also, as we've only really been doing it for two to three quarters, I do fully understand some of the challenges that you guys may have have, and also 38% volume increase is not something you may have projected.

I think all of those factors play into the improvement you see.

The one other thing is that some of our LNG businesses are actually cost dividend accounted because we are less than a 20% a shareholder and you get -- some quarters you get a dividend, some quarters you don't.

And finally, there is in the integrated gas business, in some businesses [we cycle in] some liquids.

We don't try and separate out, obviously, the liquids production contribution in Sakhalin.

It would be a bit meaningless.

All of those factors are playing into the ability of the [analytic] model.

But I think over time, you will see significant growth in this part of the business.

You will see the [Qatar] volumes coming in there.

And it will [set prices] at a level which you will see is not only strategically very, very relevant but gets easier for you to model over time.

Okay?

Okay.

I just had a short follow-up, if I may.

You mentioned that gearing may increase modestly through the year.

Are we talking towards the higher end of your 0% to 30% guidance?

No, I think we put $5 billion into working capital.

We could always take some of that back out again.

That's one of the factors, and then the oil price and the gas price are the others.

We are not talking anywhere near the top end .

So they aer roughly the same, really.

Okay.

Can we move on to the next question please, operator.

Thank you.

Our next question comes from Mark Gilman of The Benchmark Company.

Please go ahead with your question, sir.

Thanks.

Simon, good afternoon.

Just a couple thinks.

Could I ask you to clarify your comment I believe just a minute ago, as to whether Sakhalin liquids volumes are included within you integrated gas reported earnings?

Yes, they are in Sakhalin, and we don't -- we can't separate them -- separate earnings [stream.] It is around a quarter of the total in Sakhalin.

It's about 25,000 barrels per day, our share.

And the rest is gas.

Okay, and could I also ask you to clarify -- I believe you indicated 350 million equivalent barrel resources identified.

Was that strictly Gulf of Mexico comment?

Did that include all of [Vito]

It is strictly Gulf of Mexico.

It is Shell's share, t hough.

It is not the 100%%.

Our share of Vito in particular is 55%.

It includes everything we have seen from the wellbore so far.

It doesn't necessarily include what we might hope to see as we further appraise, particularly around Appomatox.

And obviously, potentially Vito because we have got more appraisal to do on that.

Regarding Majnoon in Iraq, thank you for your comments as to how you will treat the volumes going forward.

But what will happen with respect to the cost you incur in moving up toward the threshold level?

How will you treat those costs?

Basically the same as a production sharing contract in principle.

They are recorded as CapEx.

When you get to the trigger point you are allowed to recover them and [the] available revenues.

The revenues that are available are limited by the contract which is relatively transparent but I will not repeat it here, as long as the oil price is high enough.

There is a pretty rapid recovery of the sunk cost, and thereafter your recovery is on a quarterly basis, virtually because there is a lot of volume and a lot of available revenue to recover the cost even though the CapEx cost will be quite high.

There is not a big cash sink in Iraq.

There is going to be quite a lot of cash going in and coming out.

Okay.

So those costs will go on the balance sheet, essentially, until you reach the trigger point?

That's correct.

Okay.

And finally, just one more.

You restated your Asia Pacific gas realizations fairly significantly.

Could you discuss what that restatement was about?

[Northwest] Shelf, essentially.

In the pas, because we have an EP and GP business, we have what is in effect an artificial transfer price between EP and GP because the Northwest Shelf, like Sakhalin, is a fully integrated project.

The change is primarily Northwest Shelf, but it gives us a much more realistic basis going forward.

The gas realizations in Northwest Shelf are LNG.

Of course, Sakhalin and Qatar are also fully integrated.

Basically the rules that you would expect applied from the way that we choose to report them.

Hopefully that's clear.

Thank you, Simon.

Thanks Mark.

Thank you.

Our next question comes from Theepan Jothilingam from Morgan Stanley.

Please go ahead with your questions.

Yes.

Good afternoon, Simon.

A few questions please.

Firstly, could you tell us what type of activity you have been doing around the (audio difficulties) shale gas, tight gas, in 2010?

The second question just on [FIDs].

Perhaps if you could give us a little bit of color on what FIDs you might take this year and when you expect to take them.

Thank you.

Thanks Theepan.

Good afternoon.

The line went a little bit on the first question.

I think you were asking about this year's 2010 tight gas, shale gas activity?

In China, please.

We have taken on two 4000 square kilometer blocks in joint venture with PetroChina.

They will operate as [PCSs] They are exploration blocks.

Its acreage we know is prospective.

We know there is gas there.

What we don't know, is what is the quality of the reservoir.

Very much similar to an early North American play, we need to explore, learn from the initial wells, do the seismic, look for the sweet spots, get into the reservoir, do the frac jobs, look for the productivity.

Have we got a commercial development?

We will do early activity on both the large blocks this year.

It is probably a two-year program before we know what we've got.

So unlikely before 2012, what we would be looking at a major FID.

We may do some pilot work before then.

In the FIDs, back in March, I think we gave a really full list of the 2010, 2011 potential list.

But the two key ones we aer looking at at the moment , I would say [Mars B] second platform in the Mars basin, and Prelude, the floating LNG in Australia.

You mentioned tight gas as well, or course.

We don't take quite the same FID, but the level of spend on our tight gas, shale gas positions, particularly in eh Haynesville and in Canada, we're looking at at the moment as to what is the appropriate level of spend in the current market, on both the cost and the revenue side.

They are the key investment decisions in the next six to 12

Thank you.

Okay.

Thanks Theepan.

Let's move to the next question please, operator.

Thank you.

Our final question comes from Jon Rigby of UBS.

Please go ahead.

Thank you.

Hi Simon.

A couple of questions.

On the gas pricing, if we stand now and assume oil prices remain at the current levels, how long would you estimate before your European portfolio and Asia portfolio would catch up with where the oil prices are now?

And also within that, is there something we should take into account with the way that NAM works?

Is this high-priced gas that you are gong to sell more of in the winter than in the summer?

And then the second question, just to go back on your depreciation comment, as I understand it, you depreciated over proved developed reserves.

Can you talk about whether that is in a field by field or a region by region basis or whatever, so I can get a feel of how that depreciation charge could have moved trough the bookings?

I will start in the back and work forward.

Proved developed reserves, drive depreciation at a field level.

It is at the economic unit level.

If you can identify a cash flow associated with a given reservoir, that's the level at which you calculate depreciation.

Even within a basin you can get quite different rates of depreciation.

Sometimes it is a bit difficult to be completely unequivocal about the direction of movement.

On gas pricing, typically on average about a five month lag.

Within that there are anything between about three and six month lags.

And that applies to both LNG and the way the oil price linkage is structured in the European contract.

If you are meaning today's oil price, mid $80s, how long to catch up with that?

Well, it might be sort of late Q2, early Q3 before you get close and maybe mid Q3, late Q3 to average that amount.

Would it be fair to say you also got some upside on mix effects, if you were to normalize out your spot to oil-price linked mix as well?

Difficult to project really what the gas demand in particular in Europe is going to do.

I will say, while the cold winter has been good for demand, it has not been very good for demand projections.

We are just not able to separate out what was weather driven and what was commercial industrial recovery driven.

And that was the big drop in Europe, 15%, 20% down in some markets in 2009 versus 2008.

We really don't see real indicators of sustainable demand recovery yet.

And if that stays low, stocks are reasonable okay and reasonably high, then gas prices will still be under pressure during 2010.

Thanks.

Thanks, Jon.

I think we have one more question, operator.

Thank you.

Our final question comes from David Kline of RBS.

Please go ahead, sir.

David, are you there?

We can't hear you.

Thank you, Mr.

Kline.

Your line is open.

Please go ahead.

Mr.

Kline, your line is open.

Okay, David, if you can't hear us, I suggest you give the IR team a call later.

Apologies.

I'm told we have one more question, operator.

Thanks.

Thank you.

Our final question comes from Sergio [Montesani] from Union Credit.

Please go ahead, sir.

Good afternoon to everybody.

One quick question, if I may.

If I look at the breakdown of cash [costs] in particular production and manufacturing costs by business area, I can see that there is a reduction in cash cost here, around $1 billion.

In particular, this comes from the exploration and production division.

This is quite impressive considering also the growth you recorded in production.

This seems to suggest a folding unit production cost of around 15% year-on-year.

Can you give us an idea of [what drives this] in particularly, can you give us a clean number, [FX], contribution to pension fund and so onto to reconcile this number which is $1 billion cost savings target for 2010?

Thank you.

Thank you, Sergio.

Well spotted.

Obviously there are some impacts from all the things you mentioned, FX, pensions, if you look at the headline numbers.

We have not broken out for you this quarter specific underlying cost reductions.

They are there.

They are of the order of a few hundred million dollars for the group.

We are on track to deliver the $1 billion for the year.

And what I would expect is that by-- In Q2, we will give you a more specific update when you can see -- when we can see to be honest, the real sustainable underlying trends.

Q1 is always a low quarter because as people get used to the new budgets they have been allocated.

So that is not untypical, and Q1 is always difficult to project the full year from.

Then we'll say a bit more about that in Q2, which is probably a good segue into saying thank you very much for your questions and for the the time you've spent to join the call today.

I hope it was valuable for you in understanding results and the delivery of strategy that we are starting to see.

The second quarter results will be released on July 29, back to a Thursday, and I look forward to speaking to you all then if not before.

Thank you for your time and have a good day.

Ladies and gentlemen, this concludes today's conference.

Thanks for participating.

You may now disconnect.